[Federal Register Volume 78, Number 110 (Friday, June 7, 2013)]
[Proposed Rules]
[Pages 34431-34543]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-10191]
[[Page 34431]]
Vol. 78
Friday,
No. 110
June 7, 2013
Part II
Environmental Protection Agency
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40 CFR Part 423
Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category; Proposed Rule
Federal Register / Vol. 78 , No. 110 / Friday, June 7, 2013 /
Proposed Rules
[[Page 34432]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 423
[EPA-HQ-OW-2009-0819. FRL-9801-6; EPA-HQ-RCRA-2013-0209]
RIN 2040-AF14
Effluent Limitations Guidelines and Standards for the Steam
Electric Power Generating Point Source Category
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: EPA is proposing a regulation that would strengthen the
controls on discharges from certain steam electric power plants by
revising technology-based effluent limitations guidelines and standards
for the steam electric power generating point source category. Steam
electric power plants alone contribute 50-60 percent of all toxic
pollutants discharged to surface waters by all industrial categories
currently regulated in the United States under the Clean Water Act.
Furthermore, power plant discharges to surface waters are expected to
increase as pollutants are increasingly captured by air pollution
controls and transferred to wastewater discharges. This proposal, if
implemented, would reduce the amount of toxic metals and other
pollutants discharged to surface waters from power plants. EPA is
considering several regulatory options in this rulemaking and has
identified four preferred alternatives for regulation of discharges
from existing sources. These four preferred alternatives differ with
respect to the scope of requirements that would be applicable to
existing discharges of pollutants found in two wastestreams generated
at power plants. EPA estimates that the preferred options for this
proposed rule would annually reduce pollutant discharges by 0.47
billion to 2.62 billion pounds, reduce water use by 50 billion to 103
billion gallons, cost $185 million to $954 million, and would be
economically achievable.
DATES: Comments on this proposed rule must be received on or before
August 6, 2013. EPA will conduct a public hearing on the proposed
pretreatment standards on July 9, 2013 at 1:00 p.m. in the EPA East
Building, Room 1153, 1201 Constitution Avenue NW., Washington, DC.
ADDRESSES: Submit your comments on the proposed rule, identified by
Docket No. EPA-HQ-OW-2009-0819 by one of the following methods:
http:www.regulations.gov: Follow the on-line instructions
for submitting comments.
Email: OW-Docket@epa.gov, Attention Docket ID No. EPA-HQ-
OW-2009-0819.
Mail: Water Docket, U.S. Environmental Protection Agency,
Mail code: 4203M, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
Attention Docket ID No. EPA-HQ-OW-2009-0819. Please include three
copies.
Hand Delivery: Water Docket, EPA Docket Center, EPA West
Building Room 3334, 1301 Constitution Ave., NW., Washington, DC,
Attention Docket ID No. EPA-HQ-OW-2009-0819. Such deliveries are only
accepted during the Docket's normal hours of operation, and you should
make special arrangements for deliveries of boxed information by
calling 202-566-2426.
ADDRESSES: Submit any comments on the Coal Combustion Residuals Rule
issues discussed in Section III.D of this Federal Register Notice,
identified by Docket ID No. EPA-HQ-RCRA-2013-0209, by one of the
following methods:
http:www.regulations.gov: Follow the on-line instructions
for submitting comments.
Email: RCRA-Docket@epa.gov, Attention Docket ID No. EPA-
HQ-RCRA-2013-0209. In contrast to EPA's electronic public docket, EPA's
email system is not an ``anonymous access'' system. If you send an
email comment directly to the Docket without going through EPA's
electronic public docket, EPA's email system automatically captures
your email address. Email addresses that are automatically captured by
EPA's email system are included as part of the comment that is placed
in the official public docket, and made available in EPA's electronic
public docket.
Fax: Comments on the CCR rule issue may be faxed to 202-
566-0272; Attention Docket ID No. EPA-HQ-RCRA-2013-0209.
Mail: Send your comments on the CCR rule issue to the
Hazardous Waste Management System; Disposal Of Coal Combustion
Residuals From Electric Utilities, Attention Docket ID No. EPA-HQ-RCRA-
2013-0209, Environmental Protection Agency, Mailcode: 5305T, 1200
Pennsylvania Ave., NW., Washington, DC 20460. Please include a total of
two copies.
Hand Delivery: Deliver two copies of your comments on the
CCR rule issue discussed in this Federal Register to the Hazardous
Waste Management System; Disposal Of Coal Combustion Residuals From
Electric Utilities: Notice, Attention Docket ID No. EPA-HQ-RCRA-2013-
0209, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW.,
Washington, DC 20460. Such deliveries are only accepted during the
Docket's normal hours of operation, and special arrangements should be
made for deliveries of boxed information.
Instructions: Direct your comments to Docket No. EPA-HQ-OW-2009-
0819. EPA's policy is that all comments received will be included in
the public docket without change and may be made available online at
http://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through www.regulations.gov
or email. The www.regulations.gov Web site is an ``anonymous access''
system, which means EPA will not know your identity or contact
information unless you provide it in the body of your comment. If you
send an email comment directly to EPA without going through
www.regulations.gov your email address will be automatically captured
and included as part of the comment that is placed in the public docket
and made available on the Internet. If you submit an electronic
comment, EPA recommends that you include your name and other contact
information in the body of your comment and with any disk or CD-ROM you
submit. If EPA cannot read your comment due to technical difficulties
and cannot contact you for clarification, EPA may not be able to
consider your comment. Electronic files should avoid the use of special
characters, any form of encryption, and be free of any defects or
viruses.
Docket: All documents in the docket are listed in the
www.regulations.gov index. A detailed record index, organized by
subject, is available on EPA's Web site at http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm. Although listed in the index,
some information is not publicly available, e.g., CBI or other
information whose disclosure is restricted by statute. Certain other
material, such as copyrighted material, will be publicly available only
in hard copy. Publicly available docket materials are available either
electronically in www.regulations.gov or in hard copy at the Water
Docket in the EPA Docket Center, EPA/DC, EPA West, Room 3334, 1301
Constitution Ave. NW., Washington, DC. The Public Reading Room is open
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding
[[Page 34433]]
legal holidays. The telephone number for the Public Reading Room is
202-566-1744, and the telephone number for the Water Docket is 202-566-
2426.
Comments related to EPA's current thinking, as described in Section
III.D, regarding how a final RCRA Coal Combustion Residuals rule might
be aligned and structured to account for any final requirements adopted
under the ELGs for the Steam Electric Power Generating point source
category must be submitted to Docket ID Number Docket ID: EPA-HQ-RCRA-
2013-0209.
Pretreatment Hearing Information: EPA will conduct a public hearing
on the proposed pretreatment standards on July 9, 2013 at 1:00 p.m. in
the EPA East Building, Room 1153, 1201 Constitution Avenue NW.,
Washington, DC. No registration is required for this public hearing.
During the pretreatment hearing, the public will have an opportunity to
provide oral comment to EPA on the proposed pretreatment standards. EPA
will not address any issues raised during the hearing at that time but
these comments will be included in the public record for the rule. For
security reasons, we request that you bring photo identification with
you to the meeting. Also, if you let us know in advance of your plans
to attend, it will expedite the process of signing in. Seating will be
provided on a first-come, first-served basis. Please note that parking
is very limited in downtown Washington, and use of public transit is
recommended. The EPA Headquarters complex is located near the Federal
Triangle Metro station. Upon exiting the Metro station, walk east to
12th Street. On 12th Street, walk south to Constitution Avenue. At the
corner, turn right onto Constitution Avenue and proceed to the EPA East
Building entrance.
FOR FURTHER INFORMATION CONTACT: For technical information, contact
Jezebele Alicea-Virella, Engineering and Analysis Division, Telephone:
202-566-1755; Email: alicea.jezebele@epa.gov. For economic information,
contact James Covington, Engineering and Analysis Division, Telephone:
202-566-1034; Email: covington.james@epa.gov.
SUPPLEMENTARY INFORMATION:
Regulated Entities
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North American
industry
Category Example of regulated classification
entity system (NAICS)
code
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Industry..................... Electric Power 22111
Generation
Facilities--Electric
Power Generation.
Electric Power 221112
Generation
Facilities--Fossil
Fuel Electric Power
Generation.
Electric Power 221113
Generation
Facilities--Nuclear
Electric Power
Generation.
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This section is not intended to be exhaustive, but rather provides
a guide for readers regarding entities likely to be regulated by this
proposed action. Other types of entities that do not meet the above
criteria could also be regulated. To determine whether your facility
would be regulated by this proposed action, you should carefully
examine the applicability criteria listed in 40 CFR 423.10 and the
definitions in 40 CFR 423.11 of the rule and detailed further in
Section V--Scope/Applicability of the Proposed Rule, of this preamble.
If you still have questions regarding the proposed applicability of
this action to a particular entity, consult the person listed for
technical information in the preceding FOR FURTHER INFORMATION CONTACT
section.
How to Submit Comments
The public may submit comments in written or electronic form. (See
the ADDRESSES section above.) Electronic comments must be identified by
the Docket No. [EPA-HQ-OW-2009-0819] and must be submitted as a MS
Word, WordPerfect, or ASCII text file, avoiding the use of special
characters and any form of encryption. EPA requests that any graphics
included in electronic comments also be provided in hard-copy form. EPA
also will accept comments and data on disks in the aforementioned file
formats. Electronic comments received on this notice may be filed
online at many Federal Depository Libraries. No confidential business
information (CBI) should be sent by email.
Supporting Documentation
The rule proposed today is supported by a number of documents
including:
Technical Development Document for Proposed Effluent
Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category (TDD), Document No. EPA-821-R-13-002.
Environmental Assessment for the Proposed Effluent
Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category (Environmental Assessment), Document
No. EPA-821-R-13-003.
Benefits and Cost Analysis for the Proposed Effluent
Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category, Document No. EPA-821-R-13-004.
Regulatory Impact Analysis for Proposed Effluent
Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category (RIA), Document No. EPA-821-R-13-005.
These documents are available in the public record for this rule
and on EPA's Web site at http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm.
Overview
This preamble describes the terms, acronyms, and abbreviations used
in this notice; the background documents that support these proposed
regulations; the legal authority for the proposed rule; a summary of
the options considered for the proposal; background information; and
the technical and economic methodologies used by the Agency to develop
these proposed regulations. In addition, this preamble also solicits
comment and data from the public. The following outline summarizes the
organization of this document.
Table of Contents
I. Legal Authority
II. Executive Summary of the Proposed Rule
A. Purpose of the Regulatory Action
B. Summary of Major Provisions of the Proposed Rule
C. Summary of Costs and Benefits
III. Background
A. Clean Water Act
B. Effluent Guidelines Program
1. Best Practicable Control Technology Currently Available (BPT)
2. Best Conventional Pollutant Control Technology (BCT)
3. Best Available Technology Economically Achievable (BAT)
4. Best Available Demonstrated Control Technology (BADCT)/New
Source Performance Standards (NSPS)
5. Pretreatment Standards for Existing Sources (PSES)
6. Pretreatment Standards for New Sources (PSNS)
C. Steam Electric Effluent Guidelines Rulemaking History
D. Steam Electric Detailed Study
E. Clean Air Act (CAA) Rules
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1. Mercury and Air Toxics Standards (MATS)
2. Cross-State Air Pollution Rule (CSAPR)
3. Greenhouse Gas Emissions for New Electric Utility Generating
Units
F. Cooling Water Intake Structures
G. Coal Combustion Residuals (CCR) Proposed Rule
IV. Summary of Data Collection Activities
A. Questionnaire for the Steam Electric Power Generating
Effluent Guidelines
1. Description of the Industry Survey Components
2. Identification of Potential Questionnaire Recipients
3. Questionnaire Recipient Selection
4. Questionnaire Responses
5. Questionnaire Review
B. Engineering Site Visits
C. Field Sampling Program
D. EPA and State Sources
E. Industry Data
F. Technology Vendor Data
G. Other Sources
H. Economic Data
V. Scope/Applicability of the Proposed Rule
A. Facilities Subject to 40 CFR Part 423
B. Subcategorization
1. Age of Plant or Generating Unit
2. Geographic Location
3. Size
4. Fuel Type
VI. Industry Description
A. General Description of Industry
B. Steam Electric Process Descriptions and Wastewater Generation
1. Fly Ash and Bottom Ash Systems
2. FGD Systems
3. Flue Gas Mercury Control (FGMC) Systems
4. Combustion Residual Leachate from Surface Impoundments and
Landfills
5. Gasification Processes
6. Metal Cleaning Wastes
7. Carbon Capture and Storage Systems
C. Control and Treatment Technologies
1. FGD Wastewater
2. Fly Ash Transport Water
3. Bottom Ash Transport Water
4. Combustion Residuals Leachate from Landfills and Surface
Impoundments
5. Gasification Wastewater
6. Flue Gas Mercury Control (FGMC) Wastewater
7. Metal Cleaning Wastes
VII. Selection of Regulated Pollutants
A. Identifying the Pollutants of Concern
B. Selection of Pollutants for Regulation Under BAT/NSPS
C. Methodology for the POTW Pass Through Analysis (PSES/PSNS)
VIII. Proposed Regulation
A. Regulatory Options
1. BPT/BCT
2. Description of the BAT/NSPS/PSES/PSNS Options
3. Rationale for the Proposed Best Available Technology (BAT)
4. Rationale for the Proposed Best Available Demonstrated
Control/NSPS Technology
5. Rationale for the Proposed PSES Technology
6. Rationale for the Proposed PSNS Technology
7. Consideration of Future FGD Installations on the Analyses for
the ELG Rulemaking
8. Consideration of the Proposed CCR Rule on the Analyses for
the ELG Rulemaking
B. Timing of New Requirements
IX. Technology Costs and Pollutant Reductions
A. Methodology for Estimating Plant-Specific Costs
B. Methodology for Estimating Plant-Specific Pollutant
Reductions
1. FGD Wastewater
2. Fly Ash and Bottom Ash
3. Combustion Residual Leachate
4. FGMC and Gasification Wastewaters and Nonchemical Metal
Cleaning Wastes
C. Summary of National Engineering Costs and Pollutant
Reductions for Existing Plants
X. Approach to Determine Long-Term Averages, Variability
Factors, and Effluent Limitations and Standards
A. Criteria Used to Select Data as the Basis for the Limitations
and Standards
B. Data Used As Basis of the Limitations and Standards
1. Data Selection for Each Technology Option
2. Combining Data from Multiple Sources Within a Plant
3. Data Exclusions
C. Overview of the Limitations and Standards
1. Objective
2. Selection of Percentiles
D. Calculation of the Limitations and Standards
1. Calculation of Option Long-Term Average
2. Calculation of Option Variability Factors and Limitations
3. Adjustment for Autocorrelation Factors
E. Long-Term Average, Variability Factors, and Limitations for
Each Treatment Option
F. Engineering Review of Limitations and Standards
1. Comparison of Limitations to Effluent Data Used As the Basis
for the Limitations
2. Comparison of the Limitations to Influent Data
XI. Economic Impact and Social Cost Analysis
A. Introduction
B. Annualized Compliance Costs
C. Social Costs
D. Economic Impacts
1. Screening-level Assessment of Impacts on Existing Plants and
Parent Entities Incurring Compliance Costs Associated with this
Proposed Rule
2. Assessment of the Impacts in the Context of Electricity
Markets
3. Summary of Economic Impacts for Existing Sources
4. Summary of Economic Impacts for New Sources
5. Assessment of Potential Electricity Price Effects
E. Employment Effects
1. Methodology
2. Findings
XII. Cost-Effectiveness Analysis
A. Methodology
B. Cost-Effectiveness Analysis for Direct Dischargers
C. Cost-Effectiveness Analysis for Indirect Dischargers
XIII. Environmental Assessment
A. Improvements in Surface Water and Ground Water Quality
B. Reduced Impacts to Wildlife
C. Reduced Human Health Cancer Risk
D. Reduced Threat of Non-Cancer Human Health Effects
E. Reduced Nutrient Impacts
F. Unquantified Environmental and Human Health Improvements
G. Other Secondary Improvements
XIV. Benefit Analysis
A. Categories of Benefits Analyzed
B. Quantification and Monetization of Benefits
1. Human Health Benefits From Surface Water Quality Improvements
2. Improved Ecological Conditions and Recreational Use Benefits
From Surface Water Quality Improvements
3. Groundwater Quality Benefits From Reduced Groundwater
Contamination
4. Market and Productivity Benefits (Benefits From Reduced
Impoundment Failures)
5. Air-Related Benefits (Reduced Mortality and Avoided Climate
Change Impacts)
6. Benefits From Reduced Water Withdrawals (Increased
Availability of Groundwater Resources)
C. Total Monetized Benefits
D. Children's Environmental Health
XV. Non-Water Quality Environmental Impacts
A. Energy Requirements
B. Air Pollution
C. Solid Waste Generation
D. Reductions in Water Use
XVI. Regulatory Implementation
A. Implementation of the Limitations and Standards
1. Timing
2. Legacy Wastes
3. Compliance Monitoring
B. Analytical Methods
C. Upset and Bypass Provisions
D. Variances and Modifications
1. Fundamentally Different Factors (FDF) Variance
2. Economic Variances
3. Water Quality Variances
4. Removal Credits
XVII. Related Acts of Congress, Executive Orders, and Agency
Initiatives
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
1. Definition of Small Entities and Estimation of the Number of
Small Entities Subject to This Proposed ELGs
2. Statement of Basis
3. Certification Statement
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
[[Page 34435]]
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
Appendix A: Definitions, Acronyms, and Abbreviations Used in This
Notice
I. Legal Authority
EPA is proposing revisions to the effluent limitations guidelines
and standards for the Steam Electric Power Generating Point Source
Category (40 CFR 423) under the authority of Sections 301, 304, 306,
307, 308, 402, and 501 of the Clean Water Act, 33 U.S.C. 1311, 1314,
1316, 1317, 1318, 1342, and 1361.
II. Executive Summary of the Proposed Rule
A. Purpose of the Regulatory Action
The steam electric power generating point source category (i.e.,
steam electric industry) consists of plants that generate electricity
from a process utilizing fossil or nuclear fuel in conjunction with a
thermal cycle employing the steam/water system as the thermodynamic
medium. The proposed regulations would strengthen the controls on
discharges from steam electric power plants by revising the technology-
based effluent limitations guidelines and standards that apply to
wastewater discharges to surface waters (i.e., direct discharges) and
to publicly owned treatment works (i.e., indirect discharges to POTWs).
The proposed requirements would reduce the amount of metals and other
pollutants discharged to surface waters from power plants.
EPA is considering several options in this rulemaking and has
identified four preferred alternatives for regulation of discharges
from existing sources. These four preferred alternatives propose the
same requirements for most wastestreams but, as described below in
Section II.B., differ in the requirements that would be established for
discharges associated with two wastestreams from existing sources. EPA
also projects different levels of pollutant reduction and cost
associated with these alternatives.
EPA estimates that the preferred regulatory options would reduce
pollutant discharges by 0.47 billion to 2.62 billion pounds annually,
and reduce water use by 50 billion to 103 billion gallons per year. EPA
predicts substantial environmental and ecological improvements would
result under the preferred regulatory options, along with reduced
impacts to wildlife and human health.
The current regulations, which were last updated in 1982, do not
adequately address the toxic pollutants discharged from the electric
power industry, nor have they kept pace with process changes that have
occurred over the last three decades. The development of new
technologies for generating electric power (e.g., coal gasification)
and the widespread implementation of air pollution controls (e.g., flue
gas desulfurization (FGD), selective catalytic reduction (SCR), and
flue gas mercury controls (FGMC)) have altered existing wastestreams or
created new wastewater streams at many power plants.
As a result, each year the pollutant discharges from this industry
are increasing in volume and total mass, and currently account for
approximately 50-60 percent of all toxic pollutants discharged into
surface waters by all industrial categories currently regulated under
the CWA. See Section 3.2.2 of the Environmental Assessment for the
Proposed Effluent Limitations Guidelines and Standards for the Steam
Electric Power Generating Point Source Category (Environmental
Assessment)--EPA 821-R-13-003. The main pollutants of concern for these
discharges include metals (e.g., mercury, arsenic, selenium), nitrogen,
and total dissolved solids (TDS). As discussed in Section XIII and the
Environmental Assessment report, there are numerous documented
instances of environmental impact associated with these power plant
discharges, such as harm to human health, harm to aquatic life,
contamination of sediment, and detrimental impacts to wildlife. Water
quality modeling, in addition to the documented damage cases,
corroborates these impacts and indicates that the toxic discharges are
a source of widespread aquatic-life impacts, and a source of increased
cancer and non-cancer risks in humans, and toxic metal bioaccumulation
in wildlife. These discharges also contribute large cumulative nutrient
pollutant loads to sensitive watersheds, upsetting the natural balance
of such waterbodies as the Great Lakes and the Chesapeake Bay.
This proposed rule would reduce current toxic and other pollutant
discharges and their associated impacts. In general, depending on the
option, the proposed rule would establish new or additional
requirements for wastewaters associated with the following processes
and byproducts: Flue gas desulfurization (FGD), fly ash, bottom ash,
flue gas mercury control, combustion residual leachate from landfills
and surface impoundments, nonchemical metal cleaning wastes, and
gasification of fuels such as coal and petroleum coke. In addition to
the proposed requirements, as part of this rulemaking EPA is
considering establishing best management practices (BMP) requirements
that would apply to surface impoundments containing coal combustion
residuals (e.g., ash ponds, FGD ponds). EPA is also considering
establishing a voluntary program that would provide incentives for
existing power plants that dewater and close their surface impoundments
containing combustion residuals, and for power plants that eliminate
the discharge of all process wastewater (excluding cooling water
discharges).
The major provisions of the proposed rule are summarized below. In
addition, the proposed requirements and the technologies that serve as
the basis for these requirements are explained in more detail in
Section VIII of this preamble.
B. Summary of Major Provisions of the Proposed Rule
Depending on the option, EPA is proposing to revise or establish
Best Available Technology Economically Achievable (BAT), New Source
Performance Standards (NSPS), Pretreatment Standards for Existing
Sources (PSES) and Pretreatment Standards for New Sources (PSNS) that
apply to discharges of pollutants found in the following wastestreams:
FGD wastewater, fly ash transport water, bottom ash transport water,
combustion residual leachate from landfills and surface impoundments,
nonchemical metal cleaning wastes, and wastewater from flue gas mercury
control (FGMC) systems and gasification systems.
EPA has identified four preferred alternatives for regulation of
existing discharges in the proposed rule (and it has identified one
preferred alternative for regulation of new sources). These four
preferred alternatives are summarized below.
Discharges directly to surface water from existing facilities--For
existing sources that discharge directly to surface water, with the
exception of oil-fired generating units and small generating units
(i.e., 50 MW or smaller), under one preferred alternative for BAT
(referred to as Option 3a in this proposal) the proposed rule would
establish BAT for wastestreams from these sources that include:
[[Page 34436]]
``Zero discharge'' effluent limit for all pollutants in
fly ash transport water and wastewater from flue gas mercury control
systems;
Numeric effluent limits for mercury, arsenic, selenium and
TDS in discharges of wastewater from gasification processes;
Numeric effluent limits for copper and iron in discharges
of nonchemical metal cleaning wastes; \1\ and
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\1\ As described in Section VIII, EPA is proposing to exempt
from new copper and iron BAT limitations any existing discharges of
nonchemical metal cleaning wastes that are currently authorized
without iron and copper limits. For these discharges, BAT limits
would be set equal to BPT limits applicable to low volume wastes.
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Effluent limits for bottom ash transport water and
combustion residual leachate from landfills and surface impoundments
that are equal to the current Best Practicable Control Technology
Currently Available (BPT) effluent limits for these discharges (i.e.,
numeric effluent limits for TSS and oil and grease.
Under a second preferred alternative for BAT (referred to as Option
3b in this proposal), the proposed rule would establish numeric
effluent limits for mercury, arsenic, selenium, and nitrate-nitrite in
discharges of FGD wastewater from certain steam electric facilities
(those with a total plant-level wet scrubbed capacity of 2,000 MW or
greater \2\). All other proposed Option 3b requirements are identical
to the proposed 3a requirements described above.
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\2\ Total plant-level wet scrubbed capacity is calculated by
summing the nameplate capacity for all of the units that are
serviced by wet FGD systems.
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Under a third preferred alternative for BAT (referred to as Option
3 in this proposal), the proposed rule would establish numeric effluent
limits for mercury, arsenic, selenium, and nitrate-nitrite in
discharges of FGD wastewater, with the exception of small generating
units (i.e., 50 MW or smaller). All other proposed Option 3
requirements are identical to the proposed Option 3a requirements
described above.
Under a fourth preferred alternative for BAT (referred to as Option
4a in this proposal), the proposed rule would establish ``zero
discharge'' effluent limits for all pollutants in bottom ash transport
water, with the exception of all generating units with a nameplate
capacity of 400 MW or less (for those generating units that are less
than or equal to 400 MW, the proposed rule would set BAT equal to BPT
for discharges of pollutants found in the bottom ash transport water).
All other proposed Option 4a requirements are identical to the proposed
Option 3 requirements described above.
In addition, for oil-fired generating units and small generating
units (i.e., 50 MW or smaller \3\) that are existing sources and
discharge directly to surface waters, under the four preferred
alternatives for regulation of existing sources, the proposed rule
would establish effluent limits (BAT) equal to the current BPT effluent
limits for the wastestreams listed above.
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\3\ As described in Section VIII, one of the preferred options
would increase this threshold for purposes of discharges of
pollutants in bottom ash transport water only, to 400 MW or less.
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Discharges to POTWs from existing facilities--For discharges from
existing sources to POTWs, EPA is proposing to establish PSES that are
equal to the proposed BAT, with the following exceptions:
Numeric standards for discharges of nonchemical metal
cleaning wastes would be established only for copper; \4\
---------------------------------------------------------------------------
\4\ As described in Section VIII, EPA is proposing to exempt
from new copper PSES standards any existing discharges of
nonchemical metal cleaning wastes that are currently authorized
without copper limits. For these discharges, the regulations would
not specify PSES.
---------------------------------------------------------------------------
Under Options 3a, 3b, and 3 for PSES, EPA is not proposing
to establish pretreatment standards for discharges of bottom ash
transport water. Under Option 4a, EPA is not proposing to establish
pretreatment standards for discharges of bottom ash transport water for
generating units with a nameplate capacity of 400 MW or less; \5\ and
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\5\ This is because, as explained in Section VII, EPA generally
does not establish pretreatment standards for conventional
pollutants (e.g., TSS and oil and grease) because POTWs are designed
to treat these conventional pollutants.
---------------------------------------------------------------------------
Other than the pretreatment standards for nonchemical
metal cleaning wastes, EPA is not proposing to establish pretreatment
standards for existing sources for discharges from existing oil-fired
units and small generating units (i.e., 50 MW or smaller).
Discharges directly to surface water from new sources--For all
generating units that are new sources and discharge directly to surface
waters, including oil-fired generating and small generating units, the
proposed rule would establish NSPS that include:
Numeric standards for mercury, arsenic, selenium, and
nitrate-nitrite in discharges of FGD wastewater;
Maintaining the current ``zero discharge'' standard for
all pollutants in fly ash transport water for direct dischargers;
Establishing ``zero discharge'' standards for all
pollutants in bottom ash transport water and wastewater from flue gas
mercury control systems;
Numeric standards for mercury, arsenic, selenium, and TDS
in discharges of wastewater from gasification processes;
Numeric standards for mercury and arsenic in discharges of
combustion residual leachate; and
Numeric standards for TSS, oil and grease, copper, and
iron in discharges of nonchemical metal cleaning wastes.
Discharges to POTWs from new sources--For generating units that are
new sources and discharge to POTWs, including oil-fired generating and
small generating units, EPA is proposing to establish PSNS that are
equal to the proposed NSPS, except that the PSNS would also establish a
``zero discharge'' standard for all pollutants in fly ash transport
water (the current NSPS already includes a zero discharge standard for
pollutants in fly ash transport water), and the PSNS would not include
numeric standards for TSS, oil and grease, or iron in discharges of
nonchemical metal cleaning wastes.
Additional details about the proposed effluent limitations and
standards are described in Sections VIII and X of this preamble.
C. Summary of Costs and Benefits
Table II-1 summarizes the benefits \6\ and social costs for the
four preferred alternatives for this proposed rule, at 3 percent and 7
percent discount rates. Sections XI and XIV of this preamble provide
additional information regarding the costs and the benefits for the
proposed rule. Note that although Table II-1 includes the costs
associated with BMPs being considered for the proposed rule, it does
not similarly include the benefits associated with these BMPs. The BMPs
under consideration for the ELGs would reduce the probability of
impoundment failures and therefore would be expected to increase the
benefits of the proposed ELGs. EPA intends to include such benefits in
its analyses for the final rule, should EPA ultimately include the BMPs
as part of the final ELGs.
---------------------------------------------------------------------------
\6\ EPA calculated benefits for some of the options considered
for this proposal including Option 3 and Option 4. For others (3a,
3b, and 4a), EPA inferred the benefits based on the pollutant
loading reductions (lbs.) relative to the pollutant loading
reductions of Option 3 for which EPA analyzed and calculated
benefits. See Section XIV for details.
---------------------------------------------------------------------------
It is important to note that although point estimates are provided
in this table, the benefits estimates rely on complex models that
include a variety of assumptions, each of which introduces considerable
uncertainty into these estimates. This uncertainty is discussed in the
Benefits and Cost Analysis for the Proposed Effluent
[[Page 34437]]
Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category--EPA 821-R-13-004 (BCA). EPA requests
comment on the reasonableness of these assumptions, additional data
that may be available to reduce uncertainties in these estimates, and
approaches to characterize the remaining uncertainty.
Table II-1--Total Monetized Annualized Benefits and Costs for the Proposed Rule
[Millions; 2010$]
----------------------------------------------------------------------------------------------------------------
Total monetized social Total social costs
benefits -------------------------------
Preferred regulatory alternatives --------------------------------
3% 7% 3% 7%
----------------------------------------------------------------------------------------------------------------
Option 3a for Existing Sources; Option 4 for New \a\ 139.4 \a\ 104.8 $185.2 $164.5
Sources........................................
Option 3b for Existing Sources; Option 4 for New \a\ 205.5 \a\ 153.0 281.4 257.2
Sources........................................
Option 3 for Existing Sources; Option 4 for New $311.7 $230.4 572.0 545.3
Sources........................................
Option 4a for Existing Sources; Option 4 for New \a\ 482.5 \a\ 424.8 954.1 914.7
Sources........................................
----------------------------------------------------------------------------------------------------------------
\a\ EPA did not estimate benefits for Options 3a, 3b and 4a. EPA inferred benefits for Options 3a, 3b, and 4a
for illustrative purposes using elements of the more rigorous analysis done to estimate benefits for Options 3
and 4. See Section XIV for details.
III. Background
A. Clean Water Act
Congress passed the Federal Water Pollution Control Act Amendments
of 1972, also known as the Clean Water Act (CWA), to ``restore and
maintain the chemical, physical, and biological integrity of the
Nation's waters.'' 33 U.S.C. 1251(a). The CWA establishes a
comprehensive program for protecting our nation's waters. Among its
core provisions, the CWA prohibits the discharge of pollutants from a
point source to waters of the U.S., except as authorized under the CWA.
Under section 402 of the CWA, discharges may be authorized through a
National Pollutant Discharge Elimination System (NPDES) permit. The CWA
also authorizes EPA to establish national technology-based effluent
limitations guidelines and standards (ELGs) for discharges from
different categories of point sources, such as industrial, commercial,
and public sources.
The CWA authorizes EPA to promulgate nationally applicable
pretreatment standards that restrict pollutant discharges from
facilities that discharge wastewater indirectly through sewers flowing
to publicly owned treatment works (POTWs), as outlined in sections
307(b) and (c), 33 U.S.C. 1317(b) and (c). EPA establishes national
pretreatment standards for those pollutants in wastewater from indirect
dischargers that may pass through, interfere with, or are otherwise
incompatible with POTW operations. Generally, pretreatment standards
are designed to ensure that wastewaters from direct and indirect
industrial dischargers are subject to similar levels of treatment. See
CWA section 301(b), 33 U.S.C. 1311(b). In addition, POTWs are required
to implement local treatment limits applicable to their industrial
indirect dischargers to satisfy any local requirements. See 40 CFR
403.5.
Direct dischargers (i.e., those discharging directly to surface
waters) must comply with effluent limitations in NPDES permits.
Indirect dischargers, who discharge through POTWs, must comply with
pretreatment standards. Technology-based effluent limitations in NPDES
permits are derived from effluent limitations guidelines (CWA sections
301 and 304, 33 U.S.C. 1311 and 1314) and new source performance
standards (CWA section 306, 33 U.S.C. 1316) promulgated by EPA, or
based on best professional judgment (BPJ) where EPA has not promulgated
an applicable effluent guideline or new source performance standard
(CWA section 402(a)(1)(B), 33 U.S.C. 1342(a)(1)(B)). Additional
limitations based on water quality standards are also required to be
included in the permit in certain circumstances. CWA section
301(b)(1)(C), 33 U.S.C. 1311(b)(1)(C). The ELGs are established by
regulation for categories of industrial dischargers and are based on
the degree of control that can be achieved using various levels of
pollution control technology.
EPA promulgates national ELGs for major industrial categories for
three classes of pollutants: (1) Conventional pollutants (i.e., total
suspended solids, oil and grease, biochemical oxygen demand
(BOD5), fecal coliform, and pH), as outlined in CWA section
304(a)(4) and 40 CFR 401.16; (2) toxic pollutants (e.g., toxic metals
such as arsenic, mercury, selenium, and chromium; toxic organic
pollutants such as benzene, benzo-a-pyrene, phenol, and naphthalene),
as outlined in section 307(a) of the Act, 40 CFR 401.15 and 40 CFR part
423 appendix A; and (3) nonconventional pollutants, which are those
pollutants that are not categorized as conventional or toxic (e.g.,
ammonia-N, phosphorus, and total dissolved solids).
B. Effluent Guidelines Program
EPA develops effluent guidelines that are technology-based
regulations for a category of dischargers. EPA bases these regulations
on the performance of control and treatment technologies. The
legislative history of CWA section 304(b), which is the heart of the
effluent guidelines program, describes the need to press toward higher
levels of control through research and development of new processes,
modifications, replacement of obsolete plants and processes, and other
improvements in technology, taking into account the cost of controls.
Congress has also stated that EPA need not consider water quality
impacts on individual water bodies as the guidelines are developed; see
Statement of Senator Muskie (October 4, 1972), reprinted in Legislative
History of the Water Pollution Control Act Amendments of 1972, at 170.
(U.S. Senate, Committee on Public Works, Serial No. 93-1, January
1973.)
There are four types of standards applicable to direct dischargers
(plants that discharge directly to surface waters), and two standards
applicable to indirect dischargers (plants that discharge to POTWs),
described in detail below.
1. Best Practicable Control Technology Currently Available (BPT)
Traditionally, EPA defines BPT effluent limitations based on the
average of the best performances of facilities within the industry,
grouped to reflect various ages, sizes, processes, or other common
characteristics. EPA may promulgate BPT effluent limits for
conventional, toxic, and nonconventional pollutants. In specifying BPT,
EPA looks at a number of factors. EPA first considers the cost of
achieving effluent reductions in relation to the effluent reduction
benefits. The Agency also considers the age of equipment and
facilities, the
[[Page 34438]]
processes employed, engineering aspects of the control technologies,
any required process changes, non-water quality environmental impacts
(including energy requirements), and such other factors as the
Administrator deems appropriate. See CWA section 304(b)(1)(B). If,
however, existing performance is uniformly inadequate, EPA may
establish limitations based on higher levels of control than what is
currently in place in an industrial category, when based on an Agency
determination that the technology is available in another category or
subcategory, and can be practically applied.
2. Best Conventional Pollutant Control Technology (BCT)
The 1977 amendments to the CWA require EPA to identify additional
levels of effluent reduction for conventional pollutants associated
with BCT technology for discharges from existing industrial point
sources. In addition to other factors specified in section
304(b)(4)(B), the CWA requires that EPA establish BCT limitations after
consideration of a two-part ``cost reasonableness'' test. EPA explained
its methodology for the development of BCT limitations in July 9, 1986
(51 FR 24974). Section 304(a)(4) designates the following as
conventional pollutants: BOD5, total suspended solids (TSS),
fecal coliform, pH, and any additional pollutants defined by the
Administrator as conventional. The Administrator designated oil and
grease as an additional conventional pollutant on July 30, 1979 (44 FR
44501; 40 CFR 401.16).
3. Best Available Technology Economically Achievable (BAT)
BAT represents the second level of stringency for controlling
direct discharge of toxic and nonconventional pollutants. In general,
BAT ELGs represent the best available economically achievable
performance of facilities in the industrial subcategory or category. As
the statutory phrase intends, EPA considers the technological
availability and the economic achievability in determining what level
of control represents BAT. CWA section 301(b)(2)(A), 33 U.S.C.
1311(b)(2)(A). Other statutory factors that EPA considers in assessing
BAT are the cost of achieving BAT effluent reductions, the age of
equipment and facilities involved, the process employed, potential
process changes, and non-water quality environmental impacts, including
energy requirements and such other factors as the Administrator deems
appropriate. CWA section 304(b)(2)(B), 33 U.S.C. 1314(b)(2)(B). The
Agency retains considerable discretion in assigning the weight to be
accorded these factors. Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1045
(D.C. Cir. 1978). Generally, EPA determines economic achievability on
the basis of the effect of the cost of compliance with BAT limitations
on overall industry and subcategory financial conditions. BAT may
reflect the highest performance in the industry and may reflect a
higher level of performance than is currently being achieved based on
technology transferred from a different subcategory or category, bench
scale or pilot plant studies, or foreign plants. American Paper Inst.
v. Train, 543 F.2d 328, 353 (D.C. Cir. 1976); American Frozen Food
Inst. v. Train, 539 F.2d 107, 132 (D.C. Cir. 1976). BAT may be based
upon process changes or internal controls, even when these technologies
are not common industry practice. See American Frozen Foods, 539 F.2d
at 132, 140; Reynolds Metals Co. v. EPA, 760 F.2d 549, 562 (4th Cir.
1985); California & Hawaiian Sugar Co. v. EPA, 553 F.2d 280, 285-88
(2nd Cir. 1977).
4. Best Available Demonstrated Control Technology (BADCT)/New Source
Performance Standards (NSPS)
NSPS reflect effluent reductions that are achievable based on the
best available demonstrated control technology (BADCT). Owners of new
facilities have the opportunity to install the best and most efficient
production processes and wastewater treatment technologies. As a
result, NSPS should represent the most stringent controls attainable
through the application of the BADCT for all pollutants (that is,
conventional, nonconventional, and toxic pollutants). In establishing
NSPS, EPA is directed to take into consideration the cost of achieving
the effluent reduction and any non-water quality environmental impacts
and energy requirements. CWA section 306(b)(1)(B), 33 U.S.C.
1316(b)(1)(B).
5. Pretreatment Standards for Existing Sources (PSES)
Section 307(b), 33 U.S.C. 1317(b), of the Act calls for EPA to
issue pretreatment standards for discharges of pollutants to POTWs.
PSES are designed to prevent the discharge of pollutants that pass
through, interfere with, or are otherwise incompatible with the
operation of POTWs. Categorical pretreatment standards are technology-
based and are analogous to BPT and BAT effluent limitations guidelines,
and thus the Agency typically considers the same factors in
promulgating PSES as it considers in promulgating BAT. The General
Pretreatment Regulations, which set forth the framework for the
implementation of categorical pretreatment standards, are found at 40
CFR part 403. These regulations establish pretreatment standards that
apply to all non-domestic dischargers. See 52 FR 1586 (January 14,
1987).
6. Pretreatment Standards for New Sources (PSNS)
Section 307(c), 33 U.S.C. 1317(c), of the Act calls for EPA to
promulgate PSNS. Such pretreatment standards must prevent the discharge
of any pollutant into a POTW that may interfere with, pass through, or
may otherwise be incompatible with the POTW. EPA promulgates PSNS based
on best available demonstrated control technology (BADCT) for new
sources. New indirect dischargers have the opportunity to incorporate
into their facilities the best available demonstrated technologies. The
Agency typically considers the same factors in promulgating PSNS as it
considers in promulgating NSPS.
C. Steam Electric Effluent Guidelines Rulemaking History
EPA promulgated BPT, BAT, NSPS, and PSNS for the steam electric
point source category on October 8, 1974 (39 FR 36186, as amended at 40
FR 7095, February 19, 1975; 40 FR 23987, June 4, 1975) (the ``1974
regulations''). The 1974 regulations controlled two basic kinds of
discharges from power plants: (1) Thermal discharges (discharges of
heat) and (2) pollutant discharges (e.g., discharges of chlorine,
polychlorinated biphenyls (PCBs), and suspended solids). EPA
promulgated non-thermal pollutant limitations applicable to discharges
from the following wastestreams: Once-through cooling water, cooling
tower blowdown, bottom ash transport water, fly ash transport water,
boiler blowdown, metal cleaning wastes, low volume wastes, and material
storage and construction site runoff (including coal pile runoff).
On July 16, 1976, the U.S. Court of Appeals for the Fourth Circuit
remanded the following provisions of the 1974 regulations: (1) The
thermal limitations, (2) the NSPS for fly ash transport water, (3) the
rainfall runoff limitations for material storage and construction site
runoff, and (4) the BPT variance clause. All other provisions of the
regulations were upheld. Appalachian Power v. Train, 545 F.2d 1351,
1378 (4th Cir. 1976). EPA repromulgated the coal pile runoff
[[Page 34439]]
regulations in 1980. 45 FR 37432 (June 3, 1980).
EPA promulgated PSES on March 23, 1977 (42 FR 15695) applicable
only to indirect discharges of copper present in metal cleaning wastes
and PCBs and oil and grease for all wastestreams.
On November 19, 1982, EPA revised and supplemented the effluent
limitations guidelines and standards for BCT, BPT, BAT, BADCT/NSPS,
PSES, and PSNS (47 FR 52290). Under the 1982 revisions, EPA reserved
BCT limitations for all wastestreams and withdrew the BAT limitations
for TSS and oil and grease from all wastestreams because those
pollutants are properly regulated under BCT, instead of BAT. The rule
also made revisions to the following effluent limitations guidelines
and standards: BAT and NSPS for once-through cooling water; BAT, NSPS,
PSES, and PSNS for cooling tower blowdown; NSPS and PSNS for fly ash
transport water; NSPS for bottom ash transport water; and PSES and PSNS
for chemical metal cleaning wastes. Finally, the rule revised the
definition of low volume wastes to include boiler blowdown and withdrew
the separate regulation for boiler blowdown.
D. Steam Electric Detailed Study
Section 304 of the CWA requires EPA to periodically review all
effluent limitations guidelines and standards to determine whether
revisions are warranted. In addition, Section 304(m) of the CWA
requires EPA to develop and publish, biennially, a plan that
establishes a schedule for reviewing and revising promulgated national
effluent guidelines required by Section 304(b) of the CWA. During the
2005 annual review of the existing effluent guidelines for all
categories, EPA identified the regulations governing the steam electric
power generating point source category for possible revision. At that
time, publicly available data reported through the NPDES permit program
and the Toxics Release Inventory (TRI) indicated that the industry
ranked high in discharges of toxic and nonconventional pollutants.
Because of these findings, EPA initiated a more detailed study of the
category to determine if the effluent guidelines should be revised.
(See ``Steam Electric Power Generating Point Source Category: Final
Detailed Study Report'' (EPA 821-R-09-008) at http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm)
During the detailed study, EPA collected data about the industry in
several ways. EPA conducted site visits and sampled wastewater at steam
electric power plants, and EPA distributed a questionnaire to collect
data from nine companies. EPA also reviewed numerous publicly available
sources of data and coordinated with and solicited data from EPA
program offices and other government organizations (e.g., state groups
and permitting authorities), as well as industry, environmental groups,
and other stakeholders.
As part of the detailed study, EPA evaluated a range of
wastestreams and processes associated with the industry, but it
ultimately focused largely on discharges associated with coal ash
handling operations and wastewater from FGD air pollution control
systems because these sources are responsible for the majority of the
toxic pollutants currently discharged by steam electric power plants.
EPA also identified several wastestreams that are relatively new to the
industry (e.g., carbon capture wastewater), and wastestreams for which
there was little characterization data at the time of the detailed
study (e.g., gasification wastewater).
During the study, EPA found that the use of wet FGD systems (the
kind of systems that generate discharges) to control sulfur dioxide
(SO2) air emissions has increased significantly since the
last revision of the effluent guidelines in 1982. Moreover, based on
industry announcements and modeling conducted for Clean Air Act
rulemakings, the use of wet FGD systems is projected to continue to
increase in the next decade as power plants take steps to address
federal and state air pollution control requirements. EPA also found
that FGD wastewaters generally contain significant levels of metals and
other pollutants and that treatment technologies are available to treat
these pollutants in FGD wastewater; however, most plants use only
surface impoundments (e.g., settling ponds) designed primarily to
remove suspended solids from FGD wastewater.
EPA found that technologies that do not use water to transport ash
are available for handling the fly ash (a combustion residual of fine
ash particles entrained in the flue gases) generated at plants, and
that such technologies do not generate nor discharge wastewater
associated with handling fly ash (i.e., fly ash transport water). Most
of these systems are operated at newer electric generating units
because the current NSPS regulations, which were promulgated in 1982,
prohibit the discharge of pollutants in fly ash transport water. Many
older generating units have also converted to dry fly ash handling
systems that use air (i.e., pneumatic systems that use air pressure
and/or vacuum) to transport the fly ash to storage silos instead of
using water to sluice the ash (i.e., pump as a mixture of water and
ash) to surface impoundments. As a result, over 80 percent of existing
plants use dry fly ash handling. For further information, see Section
4.3.1 of the Technical Development Document for Proposed Effluent
Limitations Guidelines and Standards for the Steam Electric Power
Generating Point Source Category (TDD)--EPA 821-R-13-002.
Additionally, there are technologies available for handling the
bottom ash (i.e., a combustion residual of heavier ash particles
collected at the bottom of a boiler) that either do not use water to
transport the bottom ash away from the boiler or that manage the
transport water in a manner (i.e., closed-loop) that eliminates the
need to discharge bottom ash transport water to surface water. Neither
of these approaches discharge wastewater associated with transporting
bottom ash. In fact, some of these technologies do not even generate
bottom ash transport water. EPA estimates that by the time the final
rule is promulgated, approximately 45 percent of plants will use dry
bottom ash handling systems or will not discharge bottom ash transport
water.
From information obtained during the detailed study, EPA found that
the fly ash and bottom ash transport waters generated from wet systems
at coal-fired power plants are created in large quantities and contain
significant concentrations of metals, including arsenic, selenium and
mercury. Additionally, EPA determined that some of the metals are
present primarily in the dissolved phase, and generally are not removed
in the surface impoundments that are used to treat these wastestreams
to meet the current BPT limits for TSS and oil and grease. Based on the
record, EPA found that there are technologies readily available to
reduce or eliminate the discharge of pollutants contained in fly ash
and bottom ash transport water.
Finally, the information obtained during the study indicates that
FGD and ash transport wastewaters contain pollutants that can have
detrimental impacts to the environment. EPA reviewed publicly available
data and found documented environmental impacts that were attributable
to discharges from surface impoundments or discharges from leachate
generated from landfills containing combustion residues. EPA found that
there are a number of pollutants present in wastewaters generated at
coal-fired power plants that can impact the environment, including
metals (e.g.,
[[Page 34440]]
arsenic, selenium, mercury), TDS, and nutrients. The primary routes by
which combustion wastewater harms the environment are discharges or
spills to surface waters, leaching to ground water, and by surface
impoundments and constructed wetlands acting as attractive nuisances
that increase wildlife exposure to the pollutants contained in the
systems. The interaction of combustion wastewaters with the environment
has caused a wide range of harm to aquatic life.
Overall, from the detailed study, EPA found that the industry is
generating new wastestreams that during the previous rulemakings either
were not evaluated or were evaluated to only a limited extent due to
insufficient data. Such wastestreams include FGD wastewater, FGMC
wastewater, carbon capture wastewater, and gasification wastewaters.
EPA also found that these wastestreams, as well as other combustion-
related wastestreams at power plants (e.g., fly ash and bottom ash
transport water, leachate) contain pollutants in concentrations and
mass loadings that are causing documented environmental impacts and
that treatment technologies are available to reduce or eliminate the
pollutant discharges. For further information, see Section 6 of the
Steam Electric Power Generating Point Source Category: Detailed Study
is available online at http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm.
Based on the findings from the detailed study, which EPA issued in
2009, EPA began taking steps to revise the steam electric power
generating effluent limitations guidelines and standards.
E. Clean Air Act (CAA) Rules
1. Mercury and Air Toxics Standards (MATS)
When the CAA was amended in 1990, EPA was directed to control
mercury and other hazardous air pollutants from major sources of
emissions to the air. For power plants using fossil fuels, the
amendments required EPA to conduct a study of hazardous air pollutant
emissions. CAA Section 112(n)(1)(A). The CAA amendments also required
EPA to consider the study and other information and to make a finding
as to whether regulation was appropriate and necessary. In 2000, the
Administrator found that regulation of hazardous air pollutants,
including mercury, from coal- and oil-fired power plants was
appropriate and necessary. 65 FR 79825 (Dec. 20, 2000).
EPA published the final MATS rule on February 16, 2012. 77 FR 9304.
The rule established standards that will reduce emissions of hazardous
air pollutants including metals (e.g., mercury, arsenic, chromium,
nickel) and acid gases (e.g., hydrochloric acid, hydrofluoric acid).
Steam electric power plants may use any number of practices,
technologies, and strategies to meet the new emission limits, including
using wet and dry scrubbers, dry sorbent injection systems, activated
carbon injection systems, and fabric filters.
2. Cross-State Air Pollution Rule (CSAPR)
EPA promulgated the CSAPR in 2011 to require 28 states in the
eastern half of the United States to significantly improve air quality
by reducing power plant emissions of sulfur dioxide, nitrogen oxides
(NOX) and/or ozone-season NOX that cross state
lines and significantly contribute to ground-level ozone and/or fine
particle pollution problems in other states. The emissions of sulfur
dioxide, NOX and ozone-season NOX addressed by
the CSAPR react in the atmosphere to form PM2.5 and ground-
level ozone and are transported long distances, making it difficult for
a number of states to meet the national clean air standards that
Congress directed EPA to establish to protect public health. The U.S.
Court of Appeals for the D.C. Circuit stayed the CSAPR on December 30,
2011, and on August 21, 2012, issued an opinion vacating the rule and
ordering EPA to continue administering the Clean Air Interstate Rule.
EME Homer City Generation, L.P. v. EPA, 696 F.3d 7 (D.C. Cir. 2012). On
March 29, 2013, the United States filed a petition asking the Supreme
Court to review the D.C. Circuit decision.
3. Greenhouse Gas Emissions for New Electric Utility Generating Units
On April 13, 2012, the EPA proposed new source standards of
performance under CAA section 111 for emissions of carbon dioxide for
fossil-fuel-fired electricity generating units. 77 FR 22392. The
proposed requirements, which apply only to new sources, would require
new plants greater than 25 megawatts (MW) to meet an output-based
standard of 1,000 pounds of carbon dioxide per MW-hour of electricity
generated. EPA based this proposed standard on the performance of
natural gas combined cycle technology because EPA and others project
that even without this rule, for the foreseeable future, new fossil-
fuel-fired power plants will be built with that technology. New coal-
or petroleum coke-fired generating units could meet the standard by
using carbon capture and storage of approximately 50 percent of the
carbon dioxide in the exhaust gas when the unit begins operating or by
later installing more effective carbon capture and storage to meet the
standard on average over a 30-year period. EPA is evaluating the public
comments received on the proposal and has not determined a schedule at
this time for taking final action on the proposed rule.
F. Cooling Water Intake Structures
Section 316(b) of the CWA, 33 U.S.C. 1326(b), requires that
standards applicable to point sources under section 301 and 306 of the
Act require that the location, design, construction, and capacity of
cooling water intake structures reflect the best technology available
to minimize adverse environmental impacts. Each year, these facilities
withdraw large volumes of water from lakes, rivers, estuaries or oceans
for use in their facilities. In the process, these facilities remove
billions of aquatic organisms from waters of the United States each
year, including fish, fish larvae and eggs, crustaceans, shellfish, sea
turtles, marine mammals, and other aquatic life. The most significant
effects of these withdrawals are on early life stages of fish and
shellfish through impingement (being pinned against intake screens or
other parts at the facility) and entrainment (being drawn into cooling
water systems).
In November 2001, EPA took final action on regulations for cooling
water intake structures at new facilities that have a design intake
flow greater than 2 million gallons per day (MGD) and that have at
least one cooling water structure that uses at least 25 percent of the
water it withdraws for cooling purposes. See 40 CFR 125.81. EPA's
requirements provide a two-track approach. Under Track 1, the intake
flow at facilities that withdraw greater than 10 MGD is restricted to a
level commensurate with the level that may be achieved by use of a
closed-cycle recirculating cooling system. Facilities withdrawing
greater than 10 MGD located in areas where fisheries need additional
protection must also use technology or operational measures to further
minimize impingement mortality and entrainment. For facilities with
intakes of less than 10 MGD, the cooling water intake structures may
not exceed a fixed intake screen velocity and the quantity of intake is
restricted. Under Track 2, a facility may choose to demonstrate to the
permitting authority that other technologies will reduce the level of
adverse environmental impacts to a level that would be achieved under
Track 1.
[[Page 34441]]
In March 2011, EPA proposed standards to reduce injury and death of
fish and other aquatic life caused by cooling water intake structures
at existing power plants and manufacturing facilities. The proposed
rule would subject existing power plants and manufacturing facilities
withdrawing in excess of 2 MGD of cooling water to an upper limit on
the number of fish destroyed through impingement, as well as site-
specific entrainment mortality standards. Certain plants that withdraw
very large volumes of water would also be required to conduct studies
for use by the permit writer in determining site-specific entrainment
controls for such facilities. Finally, under the proposed rule, new
generating units at existing power plants would be required to reduce
the intake of cooling water associated with the new unit, to a level
that could be attained by using a closed-cycle cooling system. EPA is
continuing analysis and is in the process of addressing comments and
finalizing the rule.
G. Coal Combustion Residuals (CCR) Proposed Rule
CCRs are residues from the combustion of coal in steam electric
power plants and include materials such as coal ash (fly ash and bottom
ash) and FGD wastes. CCRs are currently exempt from the requirements of
Subtitle C of the Resource Conservation and Recovery Act (RCRA), which
governs the disposition and management of hazardous wastes. Potential
environmental concerns regarding the management and disposal of CCR
include pollution leaching from surface impoundments and landfills
contaminating ground water and natural resource damages and risks to
human health caused by structural failures of surface impoundments,
like that which occurred at the Tennessee Valley Authority's plant in
Kingston, Tennessee, in December 2008. The spill, which flooded more
than 300 acres of land with CCRs and contaminated the Emory and Clinch
rivers, emphasized the need for national standards to address risks
associated with the disposal of CCRs.
1. Summary of Proposed CCR Rule
On June 21, 2010, EPA co-proposed regulations that included two
approaches to regulating the disposal of CCRs generated by electric
utilities and independent power producers. Under one proposed approach,
EPA would list these residuals as ``special wastes,'' when destined for
disposal in landfills or surface impoundments, and would apply the
existing regulatory requirements established under Subtitle C of RCRA
to such wastes. Under the second proposed approach, EPA would establish
new regulations applicable specifically to CCRs under subtitle D of
RCRA, the section of the statute applicable to solid (i.e., non-
hazardous) wastes. Under both approaches, CCRs that are beneficially
used would remain exempt under the Bevill exclusion.
EPA has not yet taken final action on the proposed CCR regulations.
Certain aspects of the CCR rulemaking are discussed in this notice for
purposes of better understanding the analyses underlying this proposed
revisions to the steam electric generating ELGs. This notice is not
proposing anything new or different with respect to the CCR rulemaking
(on which the Agency has already solicited public comments) and,
therefore, is not opening up that rulemaking to further public
comments.
2. Intersection Between the Proposed ELG and Coal Combustion Residuals
Rules
This section describes EPA's current thinking on how a final RCRA
Coal Combustion Residuals (CCR) rule might be aligned and structured to
account for any final requirements adopted under the ELGs for the Steam
Electric Power Generating point source category. Consistent with RCRA
section 1006(b), EPA seeks to effectively coordinate any final RCRA
requirements with the ELG requirements, to minimize the overall
complexity of these two regulatory structures, and facilitate
implementation of engineering, financial and permitting activities.
EPA's approach would also be consistent with Executive Order 13563,
``Improving Regulation and Regulatory Review,'' issued on January 18,
2011, which emphasizes that some ``sectors and industries face a
significant number of regulatory requirements, some of which may be
redundant, inconsistent, or overlapping,'' and it directs agencies to
promote ``coordination, simplification, and harmonization.'' EPA's goal
is to ensure that the two rules work together to effectively address
the discharge of pollutants from steam electric generating facilities
and the human health and environmental risks associated with the
disposal of CCRs, without creating avoidable or unnecessary burdens.
In considering how to coordinate the potential requirements between
the two rules, EPA is guided by the following policy considerations:
first and foremost, EPA intends to ensure that its statutory
responsibilities to restore and maintain water quality under the CWA
and to protect human health and the environment under RCRA are
fulfilled. At the same time, EPA would seek to minimize the potential
for overlapping requirements to avoid imposing any unnecessary burdens
on regulated entities and to facilitate implementation and minimize the
overall complexity of the regulatory structure under which facilities
must operate. Based on these considerations, EPA is exploring two
primary means of integrating the two rules: (1) through coordinating
the design of any final substantive CCR requirements regulatory
requirements, and (2) through coordination of the timing and
implementation of final rule requirements to provide facilities with a
reasonable timeline for implementation that allows for coordinated
planning and protects electricity reliability for consumers.
Coordination of CCR Substantive Requirements with ELG Requirements.
EPA's current thinking is to focus primarily on the areas in which the
proposed CCR and ELG rules may regulate or affect the same unit or
activity. The scope of the two rules differs; although both of these
rules would affect the disposal (i.e., discharge) of coal combustion
wastes to and from surface impoundments (i.e., ``ponds'') at power
plants, only the CCR rule would regulate the disposal of CCRs in
landfills. Accordingly, in looking at how to coordinate the
requirements of the two rules, EPA is primarily focusing on any
requirements applicable to surface impoundments, rather than
modifications to any requirements applicable to CCR landfills which
would be addressed solely under any CCR rule.
One approach is to examine the ways in which EPA anticipates that
facilities are likely to modify their operations to comply with the ELG
rule, and factor the results of those assessments into EPA's evaluation
of whether separate RCRA requirements under the CCR rule are needed to
ensure protection of human health and the environment. For example, as
described in greater detail in this preamble, the ELG rule could
eliminate or reduce certain discharges to surface water, including by
controlling or eliminating wastewater that is sent to and discharged
from surface impoundments. While the ELG would not compel use of a
particular technology, EPA predicts that one possible consequence of
the proposed ELG requirements is that some number of facilities will
choose to convert their sluicing operations to dry ash-handling
systems, and will no longer send such wastes to surface impoundments.
EPA is considering how these predictions
[[Page 34442]]
might affect any specific technical requirements under RCRA that could
be applicable to CCR surface impoundments. Thus, for instance, to the
extent that facilities would no longer need to operate surface
impoundments, it is possible that this might affect the time frames (or
other requirements) necessary for closure of such impoundments.
However, it is also possible that the requirements established
under a final ELG rule could affect the development of any final CCR
rule more broadly. Since the close of the comment period on the CCR
rule, EPA has received significant new data obtained from a 2010
Information Collection Request (ICR) conducted by EPA's Office of Water
for the development of the ELG, which have the potential to affect the
risk assessment for the CCR rule. This ICR gathered information from,
among others, all 495 electric utility plants that operate coal-fired
generating units. In the June 21, 2010 proposal, EPA did not have
definitive data about the location, size, or age of the waste
management units, nor on the type or composition of the wastes
contained in surface impoundments. Consequently, the Agency relied on a
1995 industry report and a number of significant assumptions in the
2010 risk assessment supporting the proposed CCR rule.
These facility-specific data could be used in EPA's risk assessment
for any CCR rule in several ways that could significantly affect the
results of that assessment. For example, these data could be used to
determine the extent to which plumes of contamination leaching from
coal ash disposal units into groundwater are intercepted (and reduced)
by surface water bodies that exist between a disposal unit and a down-
gradient drinking water well. This information has the potential to
significantly affect the nature and extent of the risks, and would
allow EPA to better estimate the contaminant levels that people would
be expected to receive in drinking water, and to better model the
likely environmental risks (e.g., to fish and other aquatic life) from
such contaminants in surface waters. Because so many of the disposal
units (both surface impoundments and landfills) are located next to
rivers, the results of the interception analysis could reasonably be
expected to have a significant impact on the risk assessment results.
In addition, these data provide information on the location, size,
and the type of waste present in hundreds of surface impoundments that
were omitted from the data sources on which EPA relied to develop the
proposed CCR rule. These impoundments are generally, smaller than the
impoundments included in the data used to support the proposed CCR
rule, and can differ significantly from the impoundments located at
larger facilities. Exclusion of these smaller impoundments could
potentially bias the results of the risk assessment, because smaller
surface impoundments contain less waste that would be subject to
leaching, and any plumes of contamination would likely be smaller.
Similarly, these data would allow EPA to refine its analysis of the
potential risks from fugitive dust at landfills. Preliminary
comparisons of the Office of Water data indicate that currently active
portions of landfills are significantly smaller than the landfills
identified in the 1995 survey that EPA used in its assessment of the
risks from fugitive dust prepared for the proposed rule.
Although a final risk assessment for the CCR rule has not yet been
completed, reliance on the data and analyses discussed above may have
the potential to lower the CCR rule risk assessment results by as much
as an order of magnitude. If this proves to be the case, EPA's current
thinking is that, the revised risks, coupled with the ELG requirements
that the Agency may promulgate, and the increased Federal oversight
such requirements could achieve, could provide strong support for a
conclusion that regulation of CCR disposal under RCRA Subtitle D would
be adequate.
Coordination of Timelines for Implementation. The second component
of EPA's approach to integrating any CCR rule with any ELG rule relates
to the coordination of compliance and implementation deadlines. EPA's
goal is that, consistent with its statutory requirements, the
implementation dates for each rule would not require facilities to make
decisions without understanding the implications that such decisions
would have for meeting any requirements of each rule. Thus, EPA's
current approach is to enable a facility to determine whether any
changes to its operations are needed to comply with the Steam Electric
ELG--and if so, what those might be--before the facility would be
required, for example, to decide whether to close or retrofit any
surface impoundments pursuant to any CCR rule. For example, assuming
that an electric utility relied on a series of surface impoundments or
ponds to dispose of wastewater generated at the plant, EPA's current
approach would enable the facility--prior to the deadline by which the
facility would need to decide whether to retrofit or close those
surface impoundments to comply with any CCR rule--to effectively
evaluate whether it makes business sense to continue to operate those
ponds (with or without any modifications) in light of the requirements
of both rules, or whether other changes to facility operations would be
more cost-effective.
As it has in this proposed ELG rule, EPA also intends to consider,
to the extent permitted by statute, any practical constraints
facilities may face in implementing any requirements under both rules
(See, for example, Section XVI, addressing implementation issues for
the Steam Electric ELGs).
Comments on EPA's current thinking described above on how any final
CCR rule might be aligned and structured to account for any final
requirements adopted under the ELGs for the Steam Electric Power
Generating point source category should be directed to Docket ID
Number: EPA-HQ-RCRA-2013-0209. Any comments submitted on this limited
set of issues will be considered as part of the CCR rulemaking. By
contrast, comments submitted on any other issue related to the CCR rule
will be considered ``late comments'' and EPA will not respond to such
comments, nor will they be considered part of the CCR rulemaking
record.
IV. Summary of Data Collection Activities
A. Questionnaire for the Steam Electric Power Generating Effluent
Guidelines
A principal source of information used in developing this proposal
is the industry responses to a survey, the Questionnaire for the Steam
Electric Power Generating Effluent Guidelines, distributed by EPA under
the authority of section 308 of the CWA, 33 U.S.C. 1318. EPA designed
the industry survey to obtain technical information related to
wastewater generation and treatment, and economic information such as
costs of wastewater treatment technologies and financial
characteristics of potentially affected companies. The Agency consulted
with the major industry trade associations to ensure that the industry
survey would be useful and to ensure an accurate list of potential
recipients. In June 2010, EPA mailed the survey to 733 plants. In
general, plants were required to provide responses for the 2009
calendar year. The following describes the questionnaire, the recipient
selection process, and the review of the questionnaire responses.
[[Page 34443]]
1. Description of the Industry Survey Components
To obtain information relevant to the rulemaking, EPA's survey
consisted of the following nine parts:
Part A: Steam Electric Power Plant Operations;
Part B: FGD Systems;
Part C: Ash Handling;
Part D: Pond/Impoundment Systems and Other Wastewater
Treatment Operations;
Part E: Wastes from Cleaning Metal Process Equipment;
Part F: Management Practices for Ponds/Impoundments and
Landfills;
Part G: Leachate Sampling Data for Ponds/Impoundments and
Landfills;
Part H: Nuclear Power Generation; and
Part I: Economic and Financial Data.
Part A gathered information on all steam electric generating units
at the surveyed plant, the fuels used to generate electricity, air
pollution controls, cooling water, an inventory of ponds/impoundments
and landfills used for combustion residues (including coal, petroleum
coke, and oil residues), coal storage and processing, and outfall
information. Parts B through I collected economic data and detailed
technical information on certain aspects of power plant operations,
including requiring some plants to collect and analyze wastewater
samples. The process operation sections (Parts B, C, and E) included
detailed questions about the types of processes employed, dates that
certain types of equipment were installed or plans for future equipment
installations, chemical usage, operating characteristics, wastewater
generation, pollution prevention activities, and wastewater discharge
information.
In Part D of the industry survey, EPA requested detailed
information (including diagrams) on the wastewater treatment systems
(including chemical usage), discharge flow rates, and operating and
maintenance cost data (including chemical usage) (Part D). The ponds/
impoundments and landfill questions (Parts F and G) requested
information on the size, characteristics, and operation of the ponds/
impoundments and landfills located at the facilities. These sections
also obtained information on the leachate collection and treatment, and
required facilities to collect and analyze samples of untreated and
treated leachate from the ponds/impoundments and landfills that receive
combustion residues. The survey respondents were required to provide
the laboratory analytical results and additional descriptive
information about the leachate samples.
For nuclear-fueled generating units, Part H of the industry survey
requested general information on the operation of the nuclear units,
the wastewaters generated, and the treatment of those wastewaters.
The financial and economic questions (Part I) requested information
on the facilities' ownership structure and financial conditions.
The Agency used these data to evaluate process operations and
wastewater generation, identify treatment technologies in place, and
determine the feasibility of regulatory options for each plant. EPA
identified and evaluated the treatment technologies available for
treating FGD wastewater and leachate from surface impoundments and
landfills, and approaches for ash handling that reduced or eliminated
the use of water. EPA also used these data to estimate which plants may
incur compliance costs and pollutant removals associated with the
various technology control options.
EPA used survey data, along with additional data collected from
public sources, to estimate economic impacts on facilities and owning
entities under the eight main regulatory options EPA considered for
this proposal.
2. Identification of Potential Questionnaire Recipients
The Energy Information Administration (EIA), a statistical agency
of the U.S. Department of Energy (DOE), collects information on
existing electric generating plants and associated equipment to
evaluate the current status and potential trends in the industry. EPA
used the information available from the 2007 Electric Generator Report
(Form EIA-860), and supplemented it with information found in Form EIA-
923 and a survey conducted by EPA's Office of Solid Waste and Emergency
Response (OSWER), to create a listing of plants that have steam
electric power generating activities believed to be subject to the
existing Steam Electric Power Generating Effluent Guidelines.
EPA used the EIA data, which contains information on the location
of each of the plants (e.g., address, city, state), to create an
initial draft of potential questionnaire recipients that EPA shared
with industry stakeholders (e.g., the Utility Water Act Group (UWAG))
and interested environmental organizations. UWAG distributed the list
to its members and provided feedback to the Agency to correct
inaccurate addresses as well as identify plants that were not included
or plants that are no longer in operation. Based on the original EIA
data and industry feedback, EPA identified 1,197 steam electric
generating plants for the survey sample frame (i.e., a list of all
steam electric power plants from which the surveyed plants would be
selected).
3. Questionnaire Recipient Selection
As a first step in selecting questionnaire recipients, EPA grouped
all identified steam electric power plants based on the types of fuels
burned at the facility. EPA first classified the generating units into
fuel groups based on the primary and secondary energy sources reported
in the 2007 Form EIA-860. EPA used the following hierarchy to classify
the generating units: Coal, petroleum coke, gas, oil, and nuclear.
Generating units that identified either coal or petroleum coke as the
primary or secondary energy source were classified as a coal or
petroleum coke generating unit. For generating units that did not
identify coal or petroleum coke as a primary or secondary energy
source, EPA used the primary energy source to classify the generating
unit as gas, oil or nuclear. Based on the generating unit
classifications, EPA then grouped plants into the fuel categories based
on the following hierarchy: Coal, petroleum coke, combination, gas,
oil, nuclear. For example, if a plant has one coal unit and five gas
units, EPA identified the plant as a coal plant. EPA used the
``combination'' designation for plants that have at least two
generating units that have different unit-level designations (e.g.,
oil, gas, nuclear), but do not have any coal or petroleum coke units.
Because much of the focus of this proposed rule is on the FGD and
ash wastewaters, which are primarily generated at coal- and petroleum
coke-fired plants, EPA sent questionnaires to all plants that operate
coal- or petroleum coke-fired generating units. For plants without any
coal- or petroleum coke-fired generating units (i.e., gas, oil, or
nuclear-fueled), EPA sent questionnaires to a statistically selected
subset of the identified plants. EPA created four different versions of
the questionnaire to send out to plants based on the different parts of
the questionnaire:
Version 1: Parts A through I;
Version 2: Parts A, B, C, D, H, and I;
Version 3: Parts A, B, C, D, E, H, and I; and
Version 4: Parts A, E, H, and I.
In June 2010, EPA mailed the surveys to 733 power plants. EPA
mailed Version 1 of the questionnaire to 97 coal- and petroleum coke-
fired power plants, which is a subset of the total
[[Page 34444]]
number of coal- and petroleum coke-fired power plants. EPA mailed
Version 2 of the questionnaire to the remaining 407 coal- and petroleum
coke-fired power plants. EPA mailed Version 3 of the questionnaire to
20 oil-fired plants and 22 plants that burn at least two different
types of fuel (e.g., combination plants). EPA mailed Version 4 of the
questionnaire to 187 gas-fired and nuclear power plants.
4. Questionnaire Responses
EPA received completed surveys from all 733 questionnaire
recipients. A total of 53 plants certified that they were not and did
not have the capability to be engaged in steam electric power
production, would be retired by December 31, 2011, or did not generate
electricity in 2009 by burning any fossil or nuclear fuels.
5. Questionnaire Review
EPA reviewed the surveys for completeness and consistency, using
checklists for the review process to help identify potential issues
with responses (e.g., data reported in incorrect units, missing
responses). After completing the review for each plant, EPA contacted
the plant to review the potential issues identified during the review
process, if needed. EPA then created a database that contains all
survey responses. The questionnaire database in the public record
includes all information submitted for which facilities have not
asserted that the information is confidential business information
(CBI). In some instances, EPA has redacted non-CBI data to prevent the
disclosure of other data claimed as CBI.
B. Engineering Site Visits
EPA conducted 68 site visits to power plants in 22 states and Italy
between December 2006 and February 2013 to collect information about
plant operations, process wastewater generation and management
practices, and wastewater treatment systems. The primary purpose of
these site visits was to evaluate candidate best available technologies
and best available demonstrated control technologies, the changes
necessary to implement new processes or technologies, and evaluate
plants for potential inclusion in EPA's field sampling program. EPA
used information provided by UWAG, responses from the detailed study
data request, industry survey data, and information learned from
contacts with industry representatives to identify site visit
candidates. EPA based site visit selection on the type of operations at
the plant (e.g., wet FGD systems, wet fly ash or bottom ash handling,
gasification), and the plant's approach for minimizing pollutant
discharges associated with these operations (e.g., sites employing
candidate best available technologies, best available demonstrated
control technologies, or processes that reduce or eliminate pollutant
discharges.)
EPA collected detailed information from the plants visited, such as
the operations associated with wastewater generation, in-process
treatment and recycling systems, end-of-pipe treatment technologies,
and, if the plant was a candidate for sampling, the logistics of
collecting samples. EPA also obtained information regarding zero
discharge options associated with the various operations and how the
plants could potentially achieve zero discharge for some or all of
these operations. EPA prepared site visit reports summarizing the
collected information. EPA has included in the public record site visit
reports that contain all information collected during site visits for
which the plants have not asserted a claim of CBI.
C. Field Sampling Program
Between July 2007 and April 2011, EPA conducted a sampling program
at 17 different steam electric power plants in the United States and
Italy to collect wastewater characterization data and/or treatment
performance data associated with FGD wastewater, fly ash and bottom ash
wastewater, and wastewater from gasification and carbon capture
processes. EPA conducted on-site sampling (i.e., the Agency collected
the samples) at 13 of the 17 power plants. Using its authority under
CWA section 308, EPA directed seven of these EPA-sampled plants and
four additional plants not sampled by EPA to collect additional
samples, which were sent to EPA-contracted laboratories for analysis
(i.e., CWA 308 monitoring program). In general, EPA used the following
criteria to identify the plants included in the sampling program:
The plant performs steam electric power generation
activities representative of steam electric power plants (i.e., the
plant's operations are typical of operations observed at other power
plants, and therefore, are representative of more than just itself);
The plant uses coal and/or petroleum coke (the
wastestreams of interest and pollutants of concern identified in this
rulemaking are primarily associated with plants using these types of
fuels); and
The plant has the wastestreams or treatment technologies
of interest.
EPA also obtained sampling data for surface impoundment and
landfill leachate collection and treatment systems at 39 plants, as
directed by Part G of the Questionnaire for the Steam Electric Power
Generating Effluent Guidelines. This leachate sampling is not included
in the following description of the field sampling program. See Section
10.2.3 of the TDD for more information on leachate data collected under
the industry survey.
EPA's field sampling program began during its detailed study and
continued throughout this rulemaking effort. During the study, EPA
conducted one- or two-day sampling episodes at six plants to
characterize untreated wastewaters generated by coal-fired power
plants, as well as to obtain a preliminary assessment of treatment
technologies and best management practices for reducing pollutant
discharges. The types of wastewaters sampled during the detailed study
were untreated and treated FGD wastewater, fly ash wastewater, and
bottom ash wastewater.
Upon completing the detailed study, EPA subsequently selected 13
plants to collect additional wastewater characterization data and to
evaluate wastewater treatment performance. Through this effort, EPA
evaluated 10 FGD wastewater treatment systems; two gasification systems
at integrated gasification combined cycle (IGCC) plants; and one pilot-
scale carbon capture system. EPA selected these FGD systems because at
the time it believed all were among the better performing FGD
wastewater treatment systems in the industry, based on information
obtained during the site visits and discussions with industry
representatives about the design/operation of the treatment system and
optimization efforts performed at the plant. In addition, these plants
represent geographic variability, different coal types (i.e.,
bituminous, subbituminous, coal blends), and different operating
practices (e.g., baseload vs cycling). The selected IGCC systems and
the pilot-scale carbon capture system were the only known systems
operating in the U.S. power industry at the time of EPA's field
sampling program.
For the 13 plants sampled following completion of the detailed
study, samples were collected as follows:
For seven plants, EPA collected performance data for four
consecutive days and the plants also subsequently collected four sets
of samples over a four to five month period;
For four plants, the facility collected performance data
for four consecutive days;
For one plant, EPA collected performance data for three
consecutive days; and
[[Page 34445]]
For one plant, the facility collected performance data for
one day.
EPA (or the plant) collected representative samples at the influent
and effluent of the treatment system being evaluated using a
combination of 24-hour composite and grab samples, depending on the
sample location and the parameter to be analyzed. EPA analyzed the
samples for up to 64 parameters, including conventional pollutants
(e.g., TSS, BOD5), nonconventional pollutants (e.g., TDS,
nutrients), and metals. For samples collected by EPA, EPA quantified
both the total amount of metal and the dissolved portion only. For
samples collected by the plants, EPA quantified the total amount of
metal. Prior to initiating sampling activities, regardless of who
collected the samples, EPA developed sampling plans that detailed the
procedures for sample collection, including the pollutants to be
sampled, location of the sampling points, and sample collection,
preservation, and shipment techniques.
Subsequent to the EPA and industry sampling efforts, EPA prepared a
report summarizing the wastewater treatment processes, sampling
procedures, and analytical results. EPA has included in the public
record these reports containing all information collected for which a
facility has not asserted a confidentiality claim or which would
indirectly reveal information claimed to be CBI.
D. EPA and State Sources
EPA collected information from the Agency's databases and
publications, states, and permitting authorities, including the
following:
Information on current and proposed permitting practices
for the steam electric industry from a review of selected NPDES permits
and accompanying fact sheets;
Input from EPA and state permitting authorities regarding
implementation of the existing Steam Electric Power Generating effluent
guidelines;
Background information on the steam electric industry from
documents prepared during the development of the existing Steam
Electric Power Generating effluent guidelines (i.e., the 1974 and 1982
rulemakings);
Information from a survey of the industry conducted for
the Cooling Water Intake Structures rulemaking;
Information from EPA's Office of Air and Radiation (OAR),
including Integrated Planning Model (IPM) projections based on recent
air rules (i.e., CAIR/CSAPR rule and MATS);
Information from EPA's Office of Research and Development
(ORD) characterizing CCR and the potential leaching of pollutants from
CCRs stored or disposed of in landfills and surface impoundments;
Data provided by the North Carolina Department of
Environment and Natural Resources for one plant that operates an
anoxic/anaerobic biological treatment system for FGD wastewater; and
Information collected by EPA's OSWER, regarding surface
impoundments or other similar management units that contain CCRs at
power plants and other information gathered in support of the proposed
rule for regulating CCR under RCRA.
E. Industry Data
EPA obtained information on steam electric wastewaters and
pollutants directly from the industry through self-monitoring data, as
well as NPDES Form 2C data. Specifically, EPA requested self-monitoring
data from two power plants to support its calculation of pollutant
loading reductions from FGD wastewater treatment technologies and to
supplement the data from the EPA sampling program in the development of
ELGs for the FGD wastewater. EPA also coordinated with UWAG to create a
database of selected NPDES Form 2C data from UWAG's member companies.
The NPDES Form 2C database contains information about the outfalls of
coal-fired power plants that receive FGD, ash handling, or coal pile
runoff wastestreams. EPA received Form 2C data from UWAG for 86 plants
in late June 2008 and reviewed the data for use in developing the
industry profile, in particular for ash wastewater treatment
operations.
F. Technology Vendor Data
EPA gathered data from technology vendors through presentations,
conferences, meetings, and email and phone contacts to gain information
on the technologies used in the industry. EPA also used these contacts
with vendors to obtain costs to install and operate the technologies
considered as part of the proposed rule. These data informed the
development of the industry survey, the technology costs, and the
pollutant loadings estimates.
G. Other Sources
EPA obtained additional information on steam electric processes,
technologies, wastewaters, pollutants, and regulations from sources
including trade associations (e.g., UWAG), the Electric Power Research
Institute (EPRI), DOE, the U.S. Geological Survey (USGS), and
literature and Internet searches. EPA used information provided by the
Environmental Integrity Project (EIP), Earthjustice, and the Sierra
Club to document known environmental impacts caused by steam electric
power plant discharges. In addition, EPA considered information
provided in public comments during the effluent guidelines planning
process, as well as other contacts with interested stakeholders.
H. Economic Data
To conduct cost and economic impact analysis of the proposed
regulation, EPA used financial and operational data for steam electric
power plants and their parent companies collected through the Steam
Electric Questionnaire described in Section IV.A of this preamble.
EPA also used publicly available data describing current operating
and business conditions at the steam electric power plants, operators,
and parent companies, data describing economic/financial conditions in,
and the regulatory environment of, the electric power industry, as well
as data on electricity prices and electricity consumption. EPA obtained
publicly available data from the following sources: the Department of
Energy's EIA (in particular, the EIA 860, 861, and 906/920/923
databases),\7\ the U.S. Small Business Administration (SBA), the Bureau
of Labor Statistics (BLS), and the Bureau of Economic Analysis (BEA),
Securities and Exchange Commission (SEC) Forms 10-K, companies' annual
financial reports and press releases, newspapers articles, and Standard
& Poor's. Finally, EPA relied on analysis and outputs from the
Integrated Planning Model (IPM), a comprehensive electricity market
optimization model that can evaluate impacts within the context of
regional and national electricity markets (See Section XI).
---------------------------------------------------------------------------
\7\ EIA-860: Annual Electric Generator Report; EIA-861: Annual
Electric Power Industry Database; EIA-923: Utility, Non-Utility, and
Combined Heat & Power Plant Database (monthly).
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V. Scope/Applicability of the Proposed Rule
A. Facilities Subject to 40 CFR Part 423
This proposal would establish new requirements for certain plants
within the scope of the existing regulations for the steam electric
power generating point source category. The proposed requirements would
apply to discharges of wastewater associated with the following
processes and byproducts: flue gas desulfurization, fly ash, bottom
ash, combustion residual leachate, flue gas mercury control,
nonchemical metal
[[Page 34446]]
cleaning wastes, and gasification of fuels such as coal and petroleum
coke. EPA is also considering establishing best management practices
for surface impoundments receiving coal combustion residuals.
EPA is proposing to correct a typographical error in 40 CFR
423.17(d)(1) by adding a footnote that is missing from the table
specifying PSNS for cooling tower blowdown. As is clear from the
development document for the 1982 rulemaking, the footnote was intended
to appear, as it does in the corresponding table for NSPS, and its
omission was an inadvertent mistake, which EPA is now correcting. The
footnote proposed to be added reads ``No detectable amount'' and refers
to the effluent standard for 124 of the 126 priority pollutants
contained in chemicals added for cooling tower maintenance. (See
``Development Document for Final Effluent Guidelines, New Source
Performance Standards and Pretreatment Standards for the Steam Electric
Power Generating Point Source Category,'' Document No. EPA 440/1-82/
029. November 1982.)
In addition, EPA is proposing three modifications to the
applicability provision for the ELGs. These are not substantive
modifications and would not alter which generating units are regulated
by the ELGs nor impose compliance costs on the industry. Instead, the
proposed modifications would remove potential ambiguity present in the
current regulatory text by revising the text to more clearly reflect
EPA's long-standing interpretation.
First, the applicability provision in the current ELGs states, in
part, that the ELGs apply to ``an establishment primarily engaged in
the generation of electricity for distribution and sale. . . .'' 40 CFR
423.10. EPA is proposing to revise that phrase in the applicability
provision to read ``an establishment whose generation of electricity is
the predominant source of revenue or principal reason for operation . .
.'' This proposed modification would clarify that certain facilities,
such as generating units owned and operated by industrial facilities in
other sectors (e.g., petroleum refineries, pulp and paper mills) are
not included within the scope of the steam electric ELGs. In addition,
the proposed modification would clarify that certain municipal-owned
facilities, which generate and distribute electricity within a service
area (such as distributing electric power to municipal-owned
buildings), but which use accounting practices that are not commonly
thought of as a ``sale'' are nevertheless subject to the ELGs. Such
facilities have traditionally been regulated by the steam electric
ELGs, and EPA believes the proposed modification will improve
regulatory clarity.
Second, EPA is proposing a modification to the applicability
provision to clarify that fuels derived from fossil fuel are within the
scope of the current ELGs. The ELGs currently state, in part, that the
ELGs apply to discharges related to the generation of electricity
``which results primarily from a process utilizing fossil-type fuels
(coal, oil, or gas) or nuclear fuel . . .'' 40 CFR 423.10. Because
there are a number of fuel types that are derived from fossil fuel, and
which thus are fossil fuels themselves, EPA is proposing to revise that
phrase in the applicability provision to read ``which results primarily
from a process utilizing fossil-type fuel (coal, oil, or gas), fuel
derived from fossil fuel (e.g., petroleum coke, synthesis gas), or
nuclear fuel . . .''
Third, EPA is proposing to amend the applicability provision to
clarify that combined cycle systems are subject to the requirements of
the ELGs. The ELGs apply to electric generation processes that utilize
``a thermal cycle employing the steam water system as the thermodynamic
medium.'' 40 CFR 423.10. EPA's longstanding interpretation of this
provision is that the ELGs apply to all electric generation processes
with at least one prime mover that utilizes steam (if they also meet
the other factors specified in Section 423.10, including the use of
fossil or nuclear fuel). Combined cycle systems, which are generating
units composed of one or more combustion turbines operating in
conjunction with one or more steam turbines, are subject to the ELGs.
The combustion turbines for a combined cycle system operate in tandem
with the steam turbines; therefore, the ELGs apply to wastewater
discharges associated with both the combustion turbine and steam
turbine portions of the combined cycle system.
B. Subcategorization
The CWA requires EPA to consider a number of different factors when
developing ELGs for a particular industry category (see BAT factors
listed at Section 304(b)(2)(B), 33 U.S.C. Sec. 1314(b)(2)(B)). For
BAT, in addition to the technological availability and economic
achievability, these factors are the age of equipment and facilities
involved, the process employed, the engineering aspects of the
application of various types of control techniques, process changes,
the cost of achieving such effluent reduction, non-water quality
environmental impact (including energy requirements), and such other
factors the Administrator deems appropriate. One way EPA may take these
factors into account is by dividing a point source category into
groupings called ``subcategories.'' Regulating a category by
subcategory, where determined to be warranted, ensures that each
subcategory has a uniform set of ELGs that take into account technology
availability and economic achievability and other relevant factors
unique to that subcategory.
The current steam electric ELGs do not divide plants or process
operations into subcategories, although they do include different
effluent requirements for cooling water discharges from generating
units smaller than 25 MW generating capacity. For this proposed rule,
EPA evaluated whether different effluent requirements should be
established for certain facilities within the steam electric power
generating point source category using information from responses to
the industry questionnaires, site visits, sampling, and other data
collection activities (see Section IV for more details). EPA performed
analyses to assess the influence of age, size, fuel type, and
geographic location on the wastewaters generated, discharge flow rates,
pollutant concentrations, and treatment technology availability at
steam electric power plants to determine whether subcategorization was
appropriate, as discussed further below.
1. Age of Plant or Generating Unit
EPA analyzed the age of the power plants and the generating units
included in the scope of the rule. It determined that the age of the
plant by itself does not in general affect the wastewater
characteristics, the processes in place, or the ability to install the
treatment technologies evaluated as part of this rulemaking. Therefore,
EPA did not establish subcategories based on the age of the plant or
generating unit for this proposal.
2. Geographic Location
EPA analyzed the geographic location of power plants included in
the scope of the rule. It determined that the geographic location of
the plant by itself does not affect the wastewater characteristics, the
processes in place, or the ability to install the treatment
technologies evaluated as part of this rulemaking. During its
evaluation, EPA found that wet FGD systems, both wet and dry fly ash
handling systems, and both wet and dry bottom ash handling systems are
located throughout the United States, as illustrated in Section
[[Page 34447]]
4 of the TDD. Additionally, the location of the plant does not affect
the plant's ability to install the treatment technologies evaluated as
part of this rulemaking. For example, a plant in the southern United
States would be able to install and operate the chemical precipitation
and biological treatment system proposed as the BAT technology basis
for FGD wastewater. Because of the warm climate, plants in locations
such as this may find it necessary to install heat exchangers to keep
the FGD wastewater temperature at ideal operating conditions during the
summer months. EPA's approach for estimating compliance costs takes
such factors into account. Based on the information in the record
regarding the current geographic location of the various types of
systems generating the wastewaters addressed by this rulemaking and
engineering knowledge of the operational processes and candidate BAT/
NSPS treatment technologies, EPA determined that subcategories based on
plant location are not warranted.
3. Size
EPA analyzed the size (i.e., nameplate generating capacity in MW)
of the steam electric generating unit and determined that it can be an
important factor influencing the volume of the discharge flow from the
plant. Typically, as the size of the generating unit increases, the
discharge flows of ash transport water generally increase. In general,
this is to be expected because the larger the generating unit, the more
fuel it consumes, which generates more ash, and uses more water in the
water/steam thermodynamic cycle. Although the volume of the wastewater
increases with the size of the generating unit, the pollutant
characteristics of the wastewater generally are unaffected by the size
of the generating unit and any variability observed in wastewater
pollutant characteristics does not appear to be correlated to
generating capacity.
As a result of its evaluation, EPA believes that, in certain
circumstances, it would be appropriate to apply different limits for a
class of existing generating units or plants based on size. Section
VIII of this preamble discusses in greater detail EPA's proposal for
applying different standards to certain existing units.
4. Fuel Type
The type of fuel (e.g., coal, petroleum coke, oil, gas, nuclear)
used to create steam most directly influences the type and number of
wastestreams generated. For example, gas and nuclear power plants
typically generate cooling water, metal cleaning wastes (both chemical
and nonchemical), and other low volume wastestreams, but do not
generate wastewaters associated with air pollution control devices
(e.g., fly ash and bottom ash transport water, FGD wastewater). Coal,
oil, and petroleum-coke power plants may generate all of those
wastewaters. The wastestream that is most influenced by fuel selection
is the ash transport water because the quantity and quality of ash
generated from oil-fired units is different from that generated from
coal- and petroleum coke-fired units. Additionally, the quantity and
quality of ash differs based on the type of oil used in the boiler. For
example, heavy or residual oils such as No. 6 fuel oil generate fly ash
and may generate bottom ash, but lighter oils such as No. 2 fuel oil
may not generate any ash.
From an analysis of responses to the industry survey, EPA
determined that 74 percent of the steam electric units in the industry
burn more than one type of fuel (e.g., coal and oil, coal and gas).
Some of these plants may burn only one fuel at a specific time, but
burn both types of fuels during the year. Other plants may burn
multiple fuels at the same time. In cases where facilities burn
multiple fuels at the same time, it would be impossible to separate the
wastestreams by fuel type.
EPA did not identify any basis for subcategorizing gas-fired and
nuclear generating units. These generating units generally manage
nonchemical metal cleaning wastes in the same manner as other steam
electric generating units, and the proposed requirements for this
wastestream would establish limitations and standards that are equal to
current BPT limitations for existing direct dischargers.\8\
Furthermore, the gas-fired and nuclear generating units do not generate
the other six wastestreams addressed by this rulemaking. However, based
on responses to the industry survey, there are some oil-fired units
that generate and discharge fly ash and/or bottom ash transport water.
For these reasons, EPA looked carefully at oil-fired units. As a
result, EPA believes that, in certain circumstances, it is appropriate
to apply different limits to existing oil-fired generating units.
Section VIII of this preamble discusses in greater detail EPA's
proposal for applying different standards to certain existing oil-fired
units.
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\8\ As described in Section VIII, EPA is proposing to exempt
from new copper and iron BAT limitations any existing discharges of
nonchemical metal cleaning wastes that are currently authorized
without iron and copper limits. For these discharges, BAT limits
would be set equal to BPT limits applicable to low volume wastes.
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VI. Industry Description
A. General Description of Industry
The steam electric power generating point source category (i.e.,
steam electric industry) consists of plants that generate electricity
from a process utilizing fossil or nuclear fuel in conjunction with a
thermal cycle employing the steam/water system as the thermodynamic
medium. Based on responses to the industry survey, the Agency estimates
that, excluding plants reporting that they would be retired by December
2011, and those plants reporting that they did not operate fossil- or
nuclear-fueled units in 2009, there were 1,079 steam electric power
plants operating in 2009. These facilities operate an estimated 2,195-
2,230 generating units (including combined cycle systems), which have a
total nameplate generating capacity of 741,000 MW. (Note: EPA has
withheld the precise number of generating units to prevent disclosing
CBI.) Table VI-1 shows the estimated number of steam electric
generating units broken out by the five primary types of fuels used:
coal, petroleum coke, oil, gas, and nuclear.
Table VI-1--Estimated Number of Steam Electric Generating Units and
Capacity by Primary Fuel Source
------------------------------------------------------------------------
Number of Nameplate
Primary fuel source Generating units capacity (MW)
------------------------------------------------------------------------
Coal.............................. 1,080-1,090 328,000-330,000
Petroleum Coke.................... 12 1,000
Oil............................... 75-100 23,900-25,400
Gas............................... 929 282,000
Nuclear........................... 99 104,000
[[Page 34448]]
Total Industry................ 2,195-2,230 741,000
------------------------------------------------------------------------
Source: Steam Electric Technical Questionnaire Database (DCN SE01958).
As seen from these data, most of the steam electric generating
capacity (82 percent) is associated with either coal or gas. Based on
survey responses, EPA also found that most plants in the industry have
a generating capacity greater than 500 MW and may operate only one
generating unit or multiple generating units. Plants of that size
account for over 60 percent of all steam electric plants, 70 percent of
all electric generating units, and 90 percent of the electric
generating capacity.
For coal- and petroleum coke-fired plants, EPA determined that most
plants (89 percent) are discharging at least some of their wastewater
to surface waters or POTWs. Some plants operate without discharging
certain wastewaters (e.g., fly ash transport water, FGD wastewater);
however, most plants discharge at least their cooling water. Few of the
discharging plants send wastestreams addressed by this rulemaking to
POTWs. EPA identified approximately 10 coal- or petroleum coke-fired
plants that discharge their FGD wastewater and/or fly ash or bottom ash
transport water to POTWs. EPA also found that approximately 11 percent
of coal- and petroleum coke-fired power plants do not discharge any
wastewater. Most of these zero discharge plants are located in the
southwestern United States (e.g., Arizona) and use evaporation ponds to
control the wastewater.
B. Steam Electric Process Descriptions and Wastewater Generation
In the steam electric process, fuel is fed to a boiler where the
fuel is combusted. The hot gases from combustion leave the boiler and
pass through air pollution control systems prior to their emission
through a stack. The resulting heat from combustion converts water to
steam. The high-temperature, high-pressure steam leaves the boiler and
enters the turbine generator where it drives the turbine blades as it
moves from the high-pressure to the low-pressure stages of the turbine.
The lower-pressure steam leaving the turbine enters the condenser,
where steam vapor is cooled and condensed back into liquid by cooling
water. The water collected in the condenser is sent back to the boiler
where it is again converted to steam.
Combined cycle systems consist of combustion turbine electric
generating units operating in conjunction with steam turbine electric
generating units. Combustion turbines, which typically are similar to
jet engines, commonly use natural gas as the fuel. Combined cycle
systems feed the fuel into a chamber where it is combusted to generate
heat. The combustion exhaust gases are sent directly through a
combustion turbine to generate electricity. These exhaust gases still
contain useful waste heat as they exit the combustion turbine, so they
are directed to heat recovery steam generators to generate steam that
is then used to drive a steam turbine, which operates as described
above for the steam electric process. The operation of the steam
turbine electric generating unit within a combined cycle system is
virtually identical to a stand-alone steam electric generating unit,
with the exception of the boiler.
IGCC is an electric power generation process that combines
gasification technology with combined cycle systems. In an IGCC system,
a gasifier converts carbon-based feedstocks (e.g., coal or petroleum
coke) into a synthetic gas (syngas) using high temperature and
pressure. The syngas is cleaned through multiple process operations and
then combusted in a combustion turbine. As with a combined cycle
system, a heat recovery steam generator extracts the heat from the
exhaust gases to generate steam and drive a steam turbine.
Certain wastewaters generated at steam electric power plants differ
based on the fuel used; however, almost all steam electric power plants
generate some wastewaters. For example, because all steam electric
power plants use a steam water system as the thermodynamic medium, all
power plants use cooling water to condense the steam in the system.
Additionally, most steam electric power plants have a boiler blowdown
stream to purge salts from the water used in the steam water system.
Other wastewaters are generated from the use of air pollution control
systems and are more directly tied to the type of fuel burned. Coal-
and petroleum coke-fired steam electric generating units, and to a
lesser degree oil-fired units, generate a flue gas stream that contains
large quantities of particulate matter, sulfur dioxide, and nitrogen
oxides, which would be emitted to the atmosphere if they were not
cleaned from the flue gas prior to emission. Therefore, many of these
units are outfitted with air pollution control systems (e.g.,
particulate removal systems, flue gas desulfurization systems, and
NOX removal systems). Gas-fired units generate fewer
emissions of particulate matter, sulfur dioxide, and nitrogen oxides
than coal- or oil-fired units, and therefore do not typically operate
air pollution control systems to control emissions from their flue gas.
EPA determined that the wastewaters associated with these air pollution
control systems contain large quantities of metals (e.g., arsenic,
mercury, and selenium). Due to increased use of these air pollution
control systems in the last decade, and an expected increase in the
installation and use of air pollution controls over the next decade,
EPA is focusing this rulemaking, in part, on controlling the discharges
of these wastewaters.
The information in the remainder of Section VI below describing
industry practices generally presents data collected by the industry
survey and represents operational conditions for the year 2009. The
industry survey represents the most complete source of data available
to EPA regarding the operational conditions and wastewater management
practices at steam electric power plants. In some cases, where
appropriate and as specified below, EPA presents additional information
characterizing significant changes to operational practices that have
taken place since 2009.
1. Fly Ash and Bottom Ash Systems
Plants use particulate removal systems, which typically consist of
either electrostatic precipitators (ESPs) or fabric filters, to collect
fly ash and other particulates from the flue gas. The fly ash and other
particulates are captured by the ESP or fabric filters and collected in
hoppers located underneath the equipment. From the collection hoppers,
the fly ash is either
[[Page 34449]]
pneumatically transferred as dry ash to silos for temporary storage or
transported (sluiced) with water to a surface impoundment (i.e., ash
pond). The water used to transport the fly ash to the surface
impoundment is usually discharged to surface water as overflow from the
impoundment after the fly ash has settled. Of the coal- and petroleum
coke-fired steam electric generating units that generate fly ash, 66
percent operate dry fly ash transport systems, while 15 percent operate
both wet and dry fly ash transport systems. The remaining 19 percent
operate only wet fly ash transport systems, although not all of these
plants discharge their fly ash transport water. In cases where a unit
has both wet and dry handling operations, the wet handling system is
typically used as a backup to the dry system.
Fly ash transport water is one of the largest volume flows for
coal-fired power plants. Many wet transport plants (i.e., 45 percent of
plants with wet fly ash systems) sluice their fly ash continuously, and
68 percent of wet transport plants sluice their fly ash at least 12
hours per day. Based on responses to the industry survey, the average
fly ash transport water flow rate is 2.4 million gallons per day (MGD).
EPA estimates that the steam electric industry discharged a total of
81.1 billion gallons of fly ash transport water to surface water in
2009.
In addition to the particulate removal system for removing fly ash
from the flue gas, there are also systems for handling the bottom ash
that accumulates at the bottom of the furnace. The bottom ash consists
of the heavier ash particles that could not be entrained in the flue
gas and fall to the bottom of the furnace. In most furnaces, the hot
bottom ash is quenched in a water-filled hopper. Ash from the hopper is
then fed into a conveying line where it is diluted into slurry and
pumped to an impoundment or dewatering bins. The ash sent to a
dewatering bin is separated from the transport water and then disposed.
For both of these systems, the water used to transport the bottom ash
to the impoundment or dewatering bins is usually discharged to surface
water as overflow from the systems, after the bottom ash has settled.
Alternatively, some furnaces are fitted with mechanical drag systems
where the bottom ash drops into a water-filled trough, but the ash is
removed using a submerged mechanical drag conveyor that drags the
bottom ash out of the furnace. At the end of the trough, the drag chain
reaches an incline, which dewaters the bottom ash by gravity, draining
the water back to the trough as the ash moves up the conveyor. The
bottom ash is often dumped into a nearby bunker for temporary storage.
As the bottom ash continues dewatering in the nearby bunker, water that
drains from the system may be discharged; however, EPA does not
consider this water from the bunker to be bottom ash transport water
because the mechanical conveyor, and not the water, is the transport
mechanism that moves the ash away from the boiler. Instead, the
wastewater draining from the bunker would be low volume wastes. Over 65
percent of the units generating bottom ash operate wet bottom ash
transport systems, approximately 30 percent operate systems that
eliminate the use of transport water, and approximately 5 percent
operate both. Plants that have both wet and dry handling operations
typically use the wet handling system as a backup to the dry system.
Some plants that have wet bottom ash systems operate them in a manner
that does not discharge to surface water.
Bottom ash transport water is an intermittent stream from steam
electric units. The bottom ash transport water flow rates are typically
not as large as the fly ash transport water flow rates; however, bottom
ash transport water is still one of the larger volume flows for steam
electric plants. Based on responses to the industry survey, the average
bottom ash transport water flow rate is 1.8 MGD. EPA estimates that the
steam electric industry discharged a total of 157 billion gallons of
bottom ash transport water in 2009.
Power plants that generate fly ash and bottom ash can either
dispose of it in landfills or surface impoundments, or can use it in
applications such as cement or concrete manufacturing. Power plants
have used the ash in many applications that preclude the need to
dispose of the ash in landfills/impoundments.
2. FGD Systems
FGD systems remove sulfur dioxide from the flue gas so that it is
not emitted into the air. There are both wet and dry FGD systems. Dry
FGD systems generally inject an aqueous sorbent (e.g., lime) into a
spray dryer such that the water present evaporates as it contacts the
hot flue gas. The sulfur dioxide in the flue gas reacts with the lime
as it dries and results in a dry particulate product that is captured
in a downstream fabric filter; no wastewater is generated from the dry
FGD process. In wet FGD systems, the flue gas stream comes in contact
with a liquid stream containing a sorbent, typically lime or limestone,
which is used to effect the mass transfer of pollutants from the flue
gas to the liquid stream. This process not only transfers the sulfur
dioxide from the flue gas to the liquid stream, but other pollutants
(e.g., metals) as well. During this process, the lime/limestone and
sulfur dioxide react to form calcium sulfite or calcium sulfate (i.e.,
gypsum), depending on the oxidation level of the FGD system. Gypsum is
a marketable product, and as such, plants that generate gypsum
generally sell (or give away) the material for use in building
materials (e.g., wallboard). Plants that do not generate gypsum, or
only partially oxidize the calcium sulfite, generally dispose of their
FGD solids in landfills or surface impoundments. Those plants that
produce a saleable product, such as gypsum, may rinse the product cake
to reduce the level of chlorides in the final product. This wash water
may be reused or discharged to a receiving water or POTW. Additionally,
both calcium sulfite and gypsum typically require dewatering prior to
sale/disposal and this dewatering process also generates a wastewater
stream that may be reused or discharged. The FGD system generally
requires a blowdown stream to purge chlorides to prevent scaling and
corrosion of the FGD equipment.
FGD wastewater is typically an intermittent stream generated by
coal-fired power plants operating wet FGD systems. Based on responses
to the industry survey, the average FGD wastewater flow rate is 559,000
gallons per day (gpd). EPA estimates that the steam electric industry
discharged a total of 23.7 billion gallons of FGD wastewater in 2009.
Based on the responses to the industry survey, there are
approximately 401 FGD systems either currently operating or that will
be installed by January 1, 2014.\9\ Approximately 90 of the currently
operating FGD systems are dry systems that do not generate any
wastewater streams, while 311 systems are wet FGD systems.\10\
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\9\ Because EPA expects to take final action on this rule in
2014, EPA used 2014 as the baseline year for its analysis. EPA is
considering using alternative dates, such as 2022 which may better
reflect the implementation timeframe for the ELG, for the baseline
year for its analyses for the final rule.
\10\ This is not the number of steam electric power plants with
wet FGD systems. An individual steam electric power plant may
operate one or more FGD systems.
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3. Flue Gas Mercury Control (FGMC) Systems
FGMC systems remove mercury from the flue gas, so that it is not
emitted into the air. According to the responses to the industry
survey, two main types of
[[Page 34450]]
systems are currently in use in the industry: (1) Addition of oxidizers
to the coal prior to combustion, whereby the oxidized mercury is
removed in the wet FGD system; and (2) injection of activated carbon
into the flue gas which adsorbs the mercury and is captured in a
downstream particulate removal system.
The use of the oxidizers does not generate a new wastewater stream;
however, it may increase the concentration of mercury in the FGD
wastewater because the oxidized mercury is more easily removed by the
FGD system. The activated carbon injection system does have the
potential to generate a new wastestream at a plant, depending on the
location of the injection. If the injection occurs upstream of the
primary particulate removal system, then the mercury-containing carbon
(i.e., FGMC waste) is collected and handled the same way as the fly
ash. Therefore, if the fly ash is wet sluiced, then the FGMC wastes are
also wet sluiced and likely sent to the same surface impoundment. In
this case, adding the FGMC wastes to the fly ash can increase the
amount of mercury in the fly ash transport water. If the injection
occurs downstream of the primary particulate removal system, then the
plant will need a secondary particulate removal system (typically a
fabric filter) to capture the FGMC wastes. Plants typically inject the
carbon downstream of the primary particulate collection system if they
plan to market the fly ash because the carbon in FGMC wastes can make
the fly ash unmarketable. In this situation, the FGMC wastes, which
would be collected with some carry-over fly ash, could be handled
either wet or dry.
Based on the responses to the industry survey, in 2009 there were
approximately 120 operating FGMC systems, with an additional 40 planned
for installation by 2020. Approximately 90 percent of the currently
operating FGMC systems are dry systems that do not generate or affect
any wastewater streams. Approximately six percent of the currently
operating systems are wet systems. For the remaining 4 percent of the
systems, the type of handling system (e.g., wet or dry handling) is
unknown.
4. Combustion Residual Leachate From Surface Impoundments and Landfills
Combustion residuals comprise a variety of wastes from the
combustion process, including fly ash, bottom ash (which includes
boiler slag), and FGD solids (e.g., gypsum and calcium sulfite), which
are generally collected by or generated from the air pollution control
technologies. These combustion residuals may be stored at the plant in
on-site landfills or surface impoundments (i.e., ponds). Based on
industry survey results, there are approximately 228 plants that
operate combustion residual landfills and 264 plants that operate
combustion residual surface impoundments. Some plants operate both
landfills and impoundments, while other plants may operate only one or
the other, or neither type of disposal unit.
Leachate is the liquid that drains or leaches from a landfill or
surface impoundment. Most landfills have a system to collect the
leachate and some impoundments have leachate collection systems. The
two sources of leachate are precipitation that percolates through the
waste deposited in the landfill/impoundment and the liquids produced
from the combustion residuals placed in the landfill/impoundment. In
addition to leachate, stormwater that enters the impoundment or
contacts and flows over the landfill would be contaminated with
combustion residual pollutants. Leachate and contaminated stormwater
contain heavy metals and other contaminants through the contact with
the combustion residuals.
Some landfills and surface impoundments are lined. In a lined
landfill/impoundment, the leachate collected in the liner typically
flows through a collection system consisting of ditches and/or
underground pipes. From the collection system, the leachate is
transported to an impoundment (e.g., collection pond). The stormwater
collection systems typically consist of one or more small impoundments
or collection ponds. The leachate and stormwater may be treated in
separate impoundments or combined together. Some plants discharge the
effluent from these leachate impoundments, while other plants send the
leachate impoundment effluent to another impoundment handling the ash
transport water or other treatment system (e.g., constructed wetlands).
Unlined impoundments and landfills usually do not collect leachate
thereby leaving the leachate to potentially migrate to nearby ground
waters, drinking water wells, or surface waters.
Based on responses to the industry survey, approximately 100 plants
collect landfill leachate from approximately 110 existing (i.e., active
or inactive) landfills containing CCR, while approximately 50 plants
collect leachate from existing CCR surface impoundments. Another 40
plants collect leachate from both types of systems.
Leachate is an intermittent stream whose flow rate, frequency, and
duration are generally determined by weather conditions. For this
reason, leachate flow rates can vary greatly for a plant, as well as
varying from one plant to another. Additionally, there are differences
in flow rates depending on whether the landfill or surface impoundment
is active/inactive or retired. Retired landfills or surface
impoundments tend to have lower flow rates because they have been
capped or closed and, therefore, are not open to the atmospheric
rainfall. Based on the industry survey, the average active/inactive
landfill leachate flow rate was approximately 60,000 gpd. EPA estimates
that the steam electric industry discharged approximately 6.2 billion
gallons of leachate in 2009.
5. Gasification Processes
As described above, IGCC plants uses a carbon-based feedstock
(e.g., coal or petroleum coke) and subject it to high temperature and
pressure to produce a synthetic gas (``syngas'') which is used as the
fuel for a combined cycle generating unit. In these IGCC plants, after
the syngas is produced, it undergoes cleaning prior to combustion. The
cleaning processes can involve any number of the following processes:
Water scrubbing;
Carbonyl-sulfide hydrolysis;
Acid gas removal (stripping); and
Sulfur recovery.
The wastewater generated by these processes, along with any
condensate generated in flash tanks, slag handling water, or wastewater
generated from the production of sulfuric acid, are referred to as
``grey water'' or ``sour water,'' and require treatment prior to reuse
or discharge.
EPA identified two plants currently operating IGCC units, and a
third IGCC unit is scheduled to begin operation this year. A fourth
IGCC power plant is under construction and is scheduled to begin
commercial operation in 2014.
The gasification processes generally operate continuously and,
therefore, generate most of the individual gasification wastestreams
continuously. Based on the information collected during EPA's sampling
program, EPA determined the gasification wastewater transferred to the
treatment system ranged from 6,000 to 109,000 gpd, with an average flow
of 66,000 gpd.
6. Metal Cleaning Wastes
The ELGs define metal cleaning waste as ``any wastewater resulting
from cleaning [with or without chemical cleaning compounds] any metal
process equipment, including, but not limited to, boiler tube cleaning,
boiler fireside cleaning, and air preheater cleaning.'' 40
[[Page 34451]]
CFR 423.11. Plants use chemicals to remove scale and corrosion products
that accumulate on the boiler tubes and retard heat transfer. The major
constituents of boiler cleaning wastes are the metals of which the
boiler is constructed, typically iron, copper, nickel, and zinc. Boiler
firesides are commonly washed with a high-pressure water spray against
the boiler tubes while they are still hot. Fossil fuels with
significant sulfur content will produce sulfur oxides that adsorb on
air preheaters. Water with alkaline reagents is often used in air
preheater cleaning to neutralize the acidity due to the sulfur oxides,
maintain an alkaline pH, and prevent corrosion. The types of alkaline
reagents used include soda ash, caustic soda, phosphates, and
detergent.
The frequency of metal cleaning activities can vary depending on
the type of cleaning operation and individual plant practices. Some
operations occur as often as several times a day, while others occur
once every several years. Soot blowing, the process of blowing away the
soot deposits on furnace tubes, generally occurs once a day, but some
units do this as often as several hundred times a day. While 83 percent
of units responding to the industry survey use steam or service air to
blow soot, some plants may generate wastewater streams. Air heater
cleaning is another frequent cleaning activity. Sixty-six percent of
the units perform this operation at least once every two years, while
other units perform this cleaning task very infrequently, only once
every 40 years. Generally, plants use raw or potable water to clean the
air heater.
The following types of metal cleaning wastes were reported in
responses to the industry survey:
Air compressor cleaning;
Air-cooled condenser cleaning;
Air heater cleaning;
Boiler fireside cleaning;
Boiler tube cleaning;
Combustion turbine cleaning (combustion portion and/or
compressor portion);
Condenser cleaning;
Draft fan cleaning;
Economizer wash;
FGD equipment cleaning;
Heat recovery steam generator cleaning;
Mechanical dust collector cleaning;
Nuclear steam generator cleaning;
Precipitator wash;
SCR catalyst soot blowing;
Sludge lancing;
Soot blowing;
Steam turbine cleaning; and
Superheater cleaning.
7. Carbon Capture and Storage Systems
The industry is investigating carbon capture and storage systems to
remove carbon dioxide (CO2) from the flue gas. Many steam
electric power plants are considering alternatives available for
reducing CO2 emissions; however, according to the industry
survey responses, there are no full-scale carbon capture systems
currently operating. EPA obtained information about two pilot-scale
systems that operated in recent years; however, neither of these
systems is currently operating. Additionally, several plants reported
in their survey responses that they are planning to install a pilot-
scale carbon capture system and some plants reported plans to install
full-scale systems by 2020.\11\
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\11\ In order to protect CBI claims, EPA cannot provide specific
numbers.
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There are three main approaches for capturing the CO2
associated with generating electricity: Post-combustion, pre-
combustion, and oxyfuel combustion.
In post-combustion capture, the CO2 is removed
after combustion of the fossil fuel.
In pre-combustion capture, the fossil fuel is partially
oxidized, such as in a gasifier. The resulting syngas (CO and
H2) is processed to create CO2 and more
H2, and the resulting CO2 can be captured from a
relatively pure exhaust stream before combustion takes place.
In oxy-fuel combustion, also known as oxy-combustion, the
fuel is burned in oxygen instead of air. The flue gas consists of
mainly CO2 and water vapor; the latter condenses through
cooling. The result is an almost pure CO2 stream that can be
transported to the sequestration site and stored.
Based on preliminary information regarding these technologies, EPA
believes they may result in new wastewaters at steam electric power
plants. However, as these technologies are currently in the early
stages of research and development and/or pilot testing, the industry
has little information on the potential wastewaters generated from
carbon capture processes. As part of its sampling program, EPA obtained
analytical data associated with two wastestreams generated from a post-
combustion carbon capture system. Because of the small size of the
pilot-scale system, the plant transferred the wastewater off site for
treatment.
C. Control and Treatment Technologies
EPA evaluated the technologies available to control and treat
wastewater generated by the steam electric industry. Individual plants
may use one or more processes that generate wastewater streams. They
may treat these wastestreams separately or in various combinations. For
this reason, EPA evaluated available technologies for each major
wastestream separately.
1. FGD Wastewater
EPA identified 145 steam electric power plants that generate FGD
wastewater. Of these, 117 plants (81 percent) discharge FGD wastewater
after treatment using one or more of the following technologies:
Surface Impoundments: Surface impoundments (e.g., settling
ponds), designed to remove particulates from wastewater by means of
gravity, may be configured as one impoundment or a series of
impoundments. Impoundments are typically sized to allow for a certain
residence time to enable the suspended solids to settle to the bottom.
The impoundments are also designed to have sufficient capacity to allow
for temporary storage or permanent disposal of the settled solids.
Surface impoundments are not designed to remove dissolved metals.
Plants may add treatment chemicals to the impoundment, typically to
adjust pH before final discharge.
There are 63 plants (54 percent of the discharging plants) that use
surface impoundments as the only type of treatment for FGD wastewaters.
Most (49) of these plants also combine their FGD wastewater with other
plant wastewater while the remainder (14) use impoundments to treat FGD
wastewater alone. Additional plants (above and beyond the 63 plants
described in the preceding sentences) also use surface impoundments to
remove suspended solids prior to a more advanced treatment process,
such as chemical precipitation or biological treatment.
Chemical Precipitation: Some plants use chemical
precipitation systems instead of or in addition to surface
impoundments. Chemical precipitation treatment is a tank-based system
in which chemicals are added to enhance the removal of suspended solids
and dissolved solids, particularly certain dissolved metals. The
dissolved metals amenable to chemical precipitation treatment are
removed from aqueous solutions by converting soluble metal ions to
insoluble metal hydroxides or sulfides. The precipitated solids are
then removed from solution by coagulation/flocculation followed by
clarification and/or filtration. Chemical reagents such as lime
(calcium hydroxide), sodium hydroxide, and ferric chloride are used to
adjust the pH
[[Page 34452]]
of the water to reduce the solubility of the metal(s) targeted for
removal.
Some plants also use sulfide chemicals (e.g., organosulfides or
sodium sulfide) to precipitate and remove heavy metals, including
mercury. Sulfide precipitation is more effective than hydroxide
precipitation in removing mercury because mercury sulfides have lower
solubilities than mercury hydroxides. Other metal sulfide compounds
also typically have lower solubilities than metal hydroxide compounds.
Because sulfide precipitation is more expensive than hydroxide
precipitation, plants usually use hydroxide precipitation first to
remove most of the metals, and then sulfide precipitation to remove the
remaining low solubility metals. This configuration overall requires
less sulfide, thereby reducing the expense for the sulfide treatment
chemicals.
EPA identified 40 plants (34 percent of the discharging plants)
that treat their FGD wastewater using chemical precipitation (in some
cases, also employing additional treatment steps such as biological
treatment). Lime is the most commonly used treatment chemical to
perform the pH adjustment needed for these systems. Sulfide
precipitation, alone or in combination with hydroxide precipitation, is
used by 33 plants (28 percent of the discharging plants). Most plants
operating chemical precipitation treatment systems for FGD wastewater
employ ferric chloride addition (i.e., iron coprecipitation) as part of
the treatment process.
Biological Treatment: Some steam electric power plants
also treat FGD wastewater using biological treatment systems. An
anoxic/anaerobic biological system being used in the industry is
effective at removing both metals (total and dissolved) and nutrients.
This system is designed to significantly reduce nitrogen compounds and
selenium. These fixed-film bioreactors are designed for plug flow
operation and have zones of differing oxidation potential that allow
for nitrification and denitrification of the wastewater and reduction
of metals, such as selenium. The system alters the form of selenium,
reducing selenate and selenite to elemental selenium, which is then
captured by the biomass and retained in treatment system residuals.
EPA identified five plants that operate the fixed-film anoxic/
anaerobic biological treatment systems to treat FGD wastewater, and
another plant recently installed a suspended growth biological
treatment system that targets removal of selenium and other metals.\12\
Four of these six plants also operate chemical precipitation systems
prior to the biological treatment system. There are also at least four
other plants that operate aerobic/anaerobic sequencing batch reactors
to treat FGD wastewater that has already undergone chemical
precipitation. These systems are capable of removing organics and
nutrients, but are not operated in a manner to remove selenium or other
metals.
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\12\ A seventh plant is scheduled to begin operating a
biological treatment system for selenium removal in 2014. This plant
is not included in this summary of biological treatment systems.
---------------------------------------------------------------------------
Vapor-Compression Evaporation System: This type of system
uses a falling-film evaporator (or brine concentrator) to produce a
concentrated wastewater stream and a distillate stream. With
pretreatment, such as chemical precipitation and softening, brine
concentrators can reduce wastewater volumes by 80 to 90 percent. Plants
can further process the concentrated wastewater stream in a
crystallizer or spray dryer, which evaporates the remaining water to
generate a solid waste product and potentially a condensate stream. The
distillate and condensate streams may be reused within the plant or
discharged to surface waters. EPA identified two U.S. plants and four
Italian plants that treat FGD wastewater using vapor-compression
evaporation. A third U.S. plant is currently installing a vapor-
compression evaporation treatment system; it is scheduled to be
operational by the end of 2013.
Constructed Wetlands: Constructed wetlands are engineered
systems that use natural biological processes involving wetland
vegetation, soils, and microbial activity to reduce the concentrations
of metals, nutrients, and TSS in wastewater. High temperature, chemical
oxygen demand (COD), nitrates, sulfates, boron, and chlorides in
wastewater can adversely affect constructed wetlands performance. To
overcome this, plants typically dilute FGD wastewater with service
water (i.e., supply water used widely throughout the plant for a
variety of uses) before it enters a constructed wetland.
EPA identified three plants that treat their FGD wastewater using
constructed wetlands. The constructed wetlands used to treat FGD
wastewater typically are designed to treat only the FGD wastewater (and
the service water used for dilution); however, because these systems
are open to the environment, they also receive stormwater from the
surrounding areas.
Other Technologies: EPA identified several other
technologies that have been evaluated for treatment of FGD wastewater,
including iron cementation, reverse osmosis, absorption or adsorption
media, ion exchange, and electro-coagulation. Other technologies under
laboratory-scale study include polymeric chelates, taconite tailings,
and nano-scale iron reagents. Most of these technologies have been
evaluated only as pilot-scale studies; however, two of these
technologies are currently operating at full-scale to treat FGD
wastewater. One plant operates a full-scale ion exchange system that
selectively targets the removal of boron, in conjunction with a
chemical precipitation treatment stage to remove mercury and other
metals, and an anaerobic biological treatment stage to remove selenium.
Another plant treats the FGD wastewater with chemical precipitation,
followed by a full-scale treatment unit that uses cartridge filters in
combination with two sets of adsorbent media specifically designed to
enhance removals of metals. After passing through three sets of
cartridge filters (3-micron, 1-micron, and then 0.2-micron), the FGD
wastewater passes through a carbon-based media that adsorbs mercury,
and then through a ferric hydroxide-based media that adsorbs arsenic,
chromium, and other metals. The adsorbent media reportedly achieves a
maximum effluent concentration of 14 parts per trillion for mercury.
Design/Operating Practices Achieving Zero Discharge: EPA
identified four design/operating practices available enabling plants to
eliminate the discharge of wastewater from wet FGD systems: 1) Several
variations of complete recycle, 2) evaporation ponds, 3) conditioning
dry fly ash, and 4) underground injection. Of the 145 plants that
generate wastewater from FGD processes, 28 plants (19 percent) operate
in such a manner that they do not discharge wastewater to surface
waters or POTWs. Many of the plants in the southwestern United States
that generate FGD wastewater use evaporation ponds that do not
discharge.
2. Fly Ash Transport Water
Fly ash separated from boiler exhaust by electrostatic
precipitators (ESPs) or fabric filters is collected in hoppers located
underneath the equipment. From the collection hoppers, the fly ash is
either transferred as dry ash to silos for temporary storage or
transported (sluiced) with water to a surface impoundment (i.e., ash
settling pond). Plants that generate fly ash transport
[[Page 34453]]
water use surface impoundments to manage the wastewater. EPA has not
identified any facilities using more advanced treatment, such as
chemical precipitation or biological treatment, to treat fly ash
transport water. EPA identified 393 generating units (at 144 plants)
that wet sluice at least a portion of fly ash. Wet sluicing systems use
water-powered hydraulic vacuums to withdraw fly ash from the hoppers.
The ash is pulled to a separator/transfer tank, combined with sluicing
water, and pumped to the surface impoundment to remove particulates
from the wastewater by means of gravity, before discharge to a
receiving stream.
Many coal and oil-fired power plants design their fly ash handling
systems to minimize or eliminate the discharge of fly ash handling
transport water. Such approaches include:
Wet Vacuum Pneumatic System: These systems use water-
powered hydraulic vacuums for the initial withdrawal of fly ash from
the hoppers, similar to wet sluicing systems. Instead of sluicing the
ash to a surface impoundment, these systems capture the ash in a
filter-receiver (bag filter with a receiving tank) and then deposit the
dry ash in a silo.
Dry Vacuum Pneumatic System: These systems use a
mechanical exhauster to move air, below atmospheric pressure, to pull
the fly ash from the hoppers and convey it directly to a silo. The fly
ash empties from the hoppers in to the conveying system via a material
handling valve.
Pressure System: These systems use air produced by a
positive displacement blower to convey ash directly from the hopper to
a silo. Each ash collection hopper is equipped with airlock valves that
transfer the fly ash from low pressure to high pressure in the
conveying line. The airlock valves are installed at the bottom of the
hoppers and require a significant amount of space. Retrofit
installations of pressure ash handling systems may require raising the
bottom of the hopper.
Combined Vacuum/Pressure System: These systems use a dry
vacuum system to pull ash from the hoppers to a transfer station, where
the ash is transferred from the vacuum (low pressure) to ambient
pressure. From the transfer station, the fly ash is transferred via
airlock valves to a high pressure conveying line. A positive
displacement blower conveys the ash to a silo. Because the airlocks are
not located under the hopper, combination vacuum/pressure systems have
the space advantages of dry vacuum systems.
Mechanical System: Oil-fired units or other units that
generate a low volume of fly ash may use manual or systematic
approaches to remove fly ash (e.g., scraping the sides of the boilers
with sprayers or shovels, then collecting and removing the fly ash to
an intermediate storage destination or disposal).
The following identifies the number of units (and plants) in the
steam electric industry operating each of the different technologies
available to eliminate the discharge of fly ash transport water:
Wet vacuum pneumatic system--51 units (22 plants);
Dry vacuum pneumatic system--485 units (220 plants);
Pressure system--188 units (91 plants);
Combined vacuum/pressure system--223 units (102 plants);
Mechanical system--16 units (13 plants); and
Other dry systems--5 units (3 plants).
3. Bottom Ash Transport Water
Bottom ash (at times also referred to as boiler slag) is produced
as fuel is burned in a boiler and collected in hoppers or other types
of collection equipment directly below the boiler. Generally, boilers
are sloped inward, with an opening at the bottom to allow the bottom
ash to feed by gravity into collection hoppers. The hoppers contain
water to quench the hot ash. Once the hoppers are full, gates at the
bottom of the hoppers open, releasing the bottom ash and quench water
to a conveying line, where the ash is diluted with water to
approximately 20 percent solids (by weight) and pumped to a surface
impoundment or a dewatering bin for solids removal. Conveying bottom
ash in a water slurry is called wet sluicing. EPA identified 870 units
(345 plants) that wet sluice at least a portion of their bottom ash.
For further information, see Section 4.3.2 of the Technical Development
Document for Proposed Effluent Limitations Guidelines and Standards for
the Steam Electric Power Generating Point Source Category (TDD)--EPA
821-R-13-002.
Many coal and oil-fired power plants design their bottom ash
handling systems to reduce or eliminate the discharge of bottom ash
handling transport water. Available technologies include:
Mechanical Drag System: In these systems, the ash
collection hopper is replaced with a transition chute that routes the
bottom ash to a water-filled trough. In the trough, a drag chain
continuously moves the ash to an incline where it is dewatered and then
conveyed to a nearby ash collection area. Excess quench water collected
in the dewatering system is recycled to the quench water bath.
Although mechanical drag systems require little space under the
boiler they may not be suitable for all boiler configurations.
In the steam electric industry, 99 coal-fired units use mechanical
drag systems for bottom ash handling. Operators have announced plans to
retrofit mechanical drag systems on additional units by 2020. EPA
estimates that these announced retrofits include approximately 10-30
generating units. (Note: the precise value has been withheld to prevent
disclosing CBI.)
Remote Mechanical Drag System: These systems collect
bottom ash in water-filled hoppers and wet sluice the ash to a
mechanical drag system located away from the boilers. Sluice water
collected from the dewatered bottom ash is collected and reused in the
bottom ash handling system. Plants can use remote mechanical drag
systems to convert existing bottom ash handling systems with limited
space or other configuration limitations. One U.S. plant has installed
and is currently operating a remote mechanical drag system to handle
bottom ash. At least one additional plant is currently installing a
remote mechanical drag systems to handle bottom ash. Additionally, a
large U.S. power company has been evaluating installing remote
mechanical drag systems for several of its plants.
Dry Vacuum or Pressure System: These systems transport
bottom ash from the boiler to a dry hopper without using any water. The
system percolates air through the ash to cool it and combust unburned
carbon. Cooled ash then drops to a crusher and is conveyed via vacuum
or pressure to an intermediate storage destination.
Complete Recycle System: Complete recycle systems
transport bottom ash using the same processes as wet sluicing systems.
Plants can install complete recycle on existing wet sluicing units.
Instead of transporting it to an impoundment, the ash is sluiced to
dewatering bins, where it is dewatered and moved to storage. The
transport (sluice) water is treated to remove solids in a settling tank
and is recycled to the bottom ash collection system. Prior to reusing
the treated transport water, plants may add treatment chemicals to the
water to adjust pH and prevent equipment corrosion.
Vibratory Belt System: Bottom ash deposits on a vibratory
conveyor trough, where the plant cools the ash by air and ultimately
moves it through the
[[Page 34454]]
conveyor deck to an intermediate storage destination.
Mechanical System: Oil-fired units or other units that
generate a low volume of bottom ash, may use manual or systematic
approaches to removing ash that accumulates in the boiler (e.g.,
scraping the sides of the boilers with sprayers or shovels, then
collecting and removing the bottom ash to an intermediate storage
destination or disposal).
The following identifies the number of units (and plants) in the
steam electric industry operating each of the different technology
options available to eliminate or minimize the amount of bottom ash
transport water:
Mechanical drag system--99 units (74 plants);
Remote mechanical drag system--at least 2 units (2 plants)
installing systems since 2009;
Dry vacuum system--111 units (68 plants);
Dry pressure system--13 units (11 plants);
Complete recycle systems--at least 20 plants; and
Mechanical systems--38 units (19 plants).
4. Combustion Residuals Leachate From Landfills and Surface
Impoundments
Plants often treat combustion residual landfill leachate with some
of the same technologies used to treat FGD wastewater as described in
Section VI.C.1. EPA identified 102 coal-fired power plants that
generate and discharge leachate. Based on the responses to the industry
survey, 29 of these plants treat the leachate prior to discharge using
surface impoundments, constructed wetlands, or biological treatment. In
some cases, plants co-treat the leachate with FGD wastewaters and, in
some cases, treat the leachate independently.
Based on information from the industry survey and site visits,
surface impoundments are the most common type of system used to treat
combustion residual leachate from landfills and impoundments.
Constructed wetlands are the next most commonly used treatment system.
The anoxic/anaerobic biological treatment system used as the basis for
FGD wastewater effluent limits in this proposed rule is also being used
by one plant to treat leachate, with the leachate mixing with FGD
wastewater immediately prior to the bioreactor stage.
Some plants mix the leachate with fly ash prior to disposing the
ash in a landfill to control fugitive dust emissions and to improve the
handling characteristics of the dry fly ash. Leachate is also used at
some plants for dust control around ash loading areas and landfills.
Many plants will collect the leachate from a surface impoundment and
pump it directly back to the impoundment from which it originated.
Physical/chemical treatment systems are capable of achieving low
effluent concentrations of various metals and are effective at removing
many of the pollutants of concern present in leachate discharges to
surface waters. The pollutants of concern in leachate have also been
identified as pollutants of concern for FGD wastewater, fly ash
transport wastewater, bottom ash transport water, and other combustion
residuals. This is to be expected since the leachate itself comes from
landfills and surface impoundments containing the combustion residuals
and those wastes are the source for the pollutants entrained in the
leachate. Given the similarities present among the different types of
wastewaters associated with combustion residuals, combustion residual
leachate will be similarly amenable to chemical precipitation
treatment. The treatability of pollutants such as arsenic and mercury
using chemical precipitation technology is also demonstrated by
technical information compiled for ELGs promulgated for other industry
sectors. See, e.g., the TDDs supporting the ELGs for the Landfills
point source category (EPA-821-R-99-019) and the ELGs for the Metal
Products and Machinery point source category (EPA-821-B-03-001).
5. Gasification Wastewater
The treatment technologies in use at steam electric power plants
for gasification wastewater include:
Vapor-Compression Evaporation System: This type of system
is identical to the vapor-compression evaporation system described for
FGD wastewater. It uses a falling-film evaporator (or brine
concentrator) to produce a concentrated wastewater stream and a
distillate stream. The concentrated wastewater stream may be further
processed in a crystallizer or spray dryer, which evaporates the
remaining water to generate a solid waste product and potentially a
condensate stream. Facilities may reuse the distillate and condensate
streams within the plant or discharge them to surface waters.
Cyanide Destruction System: This system adds sodium
hypochlorite (i.e., bleach) to the wastewater in mixing tanks to
destroy the cyanide. The cyanide system treats the condensate and
distillate streams from both the brine concentrator and crystallizer
just prior to discharge.
EPA is aware of two plants that currently operate integrated
gasification combined cycle (IGCC) units in the United States, and a
third plant is scheduled to begin operating an IGCC unit this year. All
three of these plants currently treat or plan to treat the IGCC
wastewaters with vapor-compression evaporation systems. The IGCC plant
scheduled to begin operating this year is installing both a vapor-
compression evaporation system and a cyanide destruction system to
treat the gasification wastewater.
6. Flue Gas Mercury Control (FGMC) Wastewater
FGMC wastewater originates from activated carbon injection systems.
The system can be configured either upstream or downstream of the
primary particulate collection system. EPA identified 73 plants with
current or planned activated carbon injection systems. Of these, 58
plants operate upstream injection systems while the remaining 15 plants
inject the carbon downstream.
In cases where the injection occurs upstream of the primary
particulate collection system, plants collect and handle the mercury-
containing carbon with the fly ash. In cases where the injection occurs
downstream of the primary particulate collection system, plants collect
the mercury-containing carbon in a secondary particulate control system
(e.g., a fabric filter). As with fly ash systems, plants collect the
mercury-containing carbon in hoppers located underneath the equipment.
From the collection hoppers, plants either transfer the mercury-
containing carbon as dry ash to silos for temporary storage (67 plants;
92 percent) or transport (sluice) it with water to an ash impoundment
(6 plants; 8 percent). Water transport can result in a wastewater
discharge, typically an overflow from the impoundment. However, five of
the six plants that use water to transport the FGMC waste to a surface
impoundment do not discharge any FGMC wastewater and the remaining
plant has the capability to handle the FGMC waste using a dry system
but sometimes uses a wet system instead.
Coal-fired power plants can minimize or eliminate the discharge of
FGMC particulate handling transport water by using the same solids
handling technologies that are available for fly ash. These
technologies include:
Wet Vacuum Pneumatic System: These systems use water-
powered hydraulic vacuums to withdraw dry FGMC waste from the hoppers,
similar to wet sluicing systems. Instead of
[[Page 34455]]
sluicing the FGMC waste to a surface impoundment, these systems capture
the FGMC waste in a filter--receiver (bag filter with a receiving tank)
and then deposit it in a silo.
Dry Vacuum Pneumatic System: These systems use a
mechanical exhauster to move air, below atmospheric pressure, to pull
the FGMC waste from the hoppers and convey it directly to a silo. The
collected FGMC waste empties from the hoppers into the conveying system
via a material handling valve.
Pressure System: These systems use air produced by a
positive displacement blower to convey FGMC waste directly from the
hopper to a silo.
Combined Vacuum/Pressure System: These systems first
utilize a dry vacuum system to pull FGMC waste from the hoppers to a
transfer station, and then use a positive displacement blower to convey
it to a silo.
7. Metal Cleaning Wastes
As described in Section VI.B.6, metal cleaning wastes are generated
from cleaning any metal process equipment. Because there are many
different processes at plants that use metal equipment, there are a
variety of metal cleaning wastes that are generated. The treatment
methods used for each of the different types of metal cleaning wastes
vary to some degree depending on the specific cleaning operations.
Based on information from the industry survey, surface impoundments
and chemical precipitation systems are two of the most common types of
systems used to treat metal cleaning wastes. Other types of treatment
systems include constructed wetlands, filtration, reverse osmosis,
clarification, oil/water separation, and brine concentrators.
In addition to the treatment systems used to control the discharges
of metal cleaning wastes, some plants also employ other handling
approaches to control or eliminate the discharge of metal cleaning
wastes. For example, some plants immediately recycle the metal cleaning
wastes back to other plant operations, while other plants evaporate the
metal cleaning wastes in the boiler to evaporate the wastewater and
eliminate the discharge. Other handling operations reported in the
industry survey include offsite treatment, hazardous waste disposal,
third-party disposal, mixing with fly ash and landfilling, and deep
well injection.
Physical/chemical treatment systems are capable of reducing the
concentration of pollutants, including metals, in the wastewater.
VII. Selection of Regulated Pollutants
A. Identifying the Pollutants of Concern
The following paragraphs discuss the pollutants of concern
identified for each of the wastestreams considered for regulation in
this proposal. For the purpose of this rulemaking, pollutants of
concern are those pollutants that have been quantified in a wastestream
at sufficient frequency at treatable levels (i.e., concentrations). EPA
used the following sources of wastewater characterization data to
identify pollutants of concern in wastewater from steam electric power
plants: EPA's field sampling program, industry-supplied data including
data provided in responses to the industry survey, and various
literature sources. EPA relied primarily on its field sampling program
data because the data were collected using consistent methods and
analytical techniques for a broad range of pollutants. Therefore, where
EPA had data from its field sampling program, it preferentially used
that data. Where EPA did not collect field sampling data for a
wastestream and industry-supplied data was available, EPA used that
data. In the absence of either EPA field sampling data or industry-
supplied data, EPA used literature data.
After reviewing the available sources of data for each of the
wastestreams addressed by this rulemaking, EPA first combined the
pollutant data to create consolidated datasets representing the
concentrations of pollutants present in each wastestream prior to
treatment. EPA then eliminated all pollutants that were not detected in
any wastewater samples--any pollutants falling into this category are
not considered pollutants of concern. Finally, for the remaining
pollutants for each wastestream, EPA then identified each pollutant
that was detected at a concentration greater than or equal to ten times
the baseline value (see Section 6 of the TDD) in at least 10 percent of
all untreated process wastewater samples.\13\
---------------------------------------------------------------------------
\13\ This is consistent with the process EPA used to identify
pollutants of concern for many categories. EPA takes this approach
to ensure the pollutants are present in treatable levels.
---------------------------------------------------------------------------
EPA identified the following 34 pollutants of concern for FGD
wastewater using EPA field sampling data: one conventional pollutant
(TSS); \14\ 13 toxic pollutants, including arsenic, cyanide, mercury,
and selenium; 12 nonconventional metals; and 8 other nonconventional
pollutants (e.g., ammonia, nitrate/nitrite, and total phosphorus).
---------------------------------------------------------------------------
\14\ EPA did not analyze its field sampling data for oil and
grease. Rather, since the existing steam electric ELG currently
contains BPT limitations applicable to FGD wastewater for oil and
grease, EPA already has data from the existing rulemaking
demonstrating oil and grease is also a pollutant of concern in FGD
wastewater.
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EPA identified the following 24 pollutants of concern for fly ash
transport water using EPA field sampling data: one conventional
pollutant (TSS); \15\ 9 toxic pollutants (metals including arsenic,
lead, mercury, and selenium); 11 nonconventional pollutant metals; and
3 other nonconventional pollutants (i.e., TDS, chloride, and nitrate/
nitrite).
---------------------------------------------------------------------------
\15\ EPA did not analyze its field sampling data for oil and
grease. Rather, since the existing steam electric ELG currently
contains BPT limitations applicable to fly ash transport wastewater
for oil and grease, EPA already has data from the existing
rulemaking demonstrating oil and grease is also a pollutant of
concern in fly ash wastewater.
---------------------------------------------------------------------------
EPA was unable to obtain readily available data for untreated
bottom ash transport water for use in identifying the pollutants of
concern using the methodology described above. However, because the
pollutants found in bottom ash are constituents that are present in the
coal (or petroleum coke or oil), as is the case for fly ash, EPA
concluded that the pollutants of concern for bottom ash transport water
are identical to the pollutants of concern identified for fly ash
transport water.
EPA was also unable to obtain readily available data for
identifying the pollutants of concern in FGMC wastewater. Nevertheless,
based on process knowledge and engineering judgment, EPA concluded that
the pollutants of concern for FGMC wastewater are likely to be
identical to the pollutants of concern identified for fly ash transport
water. This is due to the fact that, when activated carbon is injected
into the flue gases, the carbon intermixes with the fly ash particles,
and then the commingled mixture of activated carbon (which adsorbs
mercury and other pollutants from the flue gases) and fly ash particles
is captured together and transferred to the FGMC wastewater.
EPA evaluated the pollutants of concern for combustion residual
leachate using industry sampling data for untreated leachate submitted
under Part G of the industry survey. EPA evaluated the landfill
leachate separately from the surface impoundment leachate. The
pollutants of concern for landfill leachate include the following: one
conventional pollutant (TSS); \16\ 3 toxic pollutants
[[Page 34456]]
(arsenic, mercury, and selenium); 9 nonconventional pollutant metals;
and 3 other nonconventional pollutants (i.e., chloride, sulfate and
TDS). The pollutants of concern for impoundment leachate include: \17\
2 toxic pollutants (i.e., arsenic and mercury), 7 nonconventional
pollutant metals, and 3 other nonconventional pollutants (i.e.,
chloride, sulfate, and TDS).
---------------------------------------------------------------------------
\16\ The landfill leachate samples were not analyzed for oil and
grease. Rather, since the existing steam electric ELG currently
contains BPT limitations applicable to combustion residual leachate
for oil and grease, EPA already has data from the existing
rulemaking demonstrating oil and grease is also a pollutant of
concern in combustion residual leachate.
\17\ The surface impoundment leachate samples were not analyzed
for oil and grease. Rather, since the existing steam electric ELG
currently contains BPT limitations applicable to combustion residual
leachate for oil and grease, EPA already has data from the existing
rulemaking demonstrating oil and grease is also a pollutant of
concern in combustion residual leachate.
---------------------------------------------------------------------------
EPA identified 19 pollutants of concern for gasification wastewater
using EPA field sampling data, including: 1 conventional pollutant
(BOD); 7 toxic pollutants (including arsenic, cyanide, mercury, and
selenium); 5 nonconventional pollutant metals; and 6 other
nonconventional pollutants.
As part of the 1974 rulemaking, EPA collected characterization data
associated with chemical and nonchemical metal cleaning wastes. Based
on the data collected during that rulemaking, EPA determined that TSS,
oil and grease, copper, and iron were pollutants of concern for this
wastestream warranting regulation and established BPT limitations for
these four pollutants in discharges of metal cleaning wastes, including
both nonchemical and chemical metal cleaning wastes. (EPA has also
established BAT, NSPS, PSES, and PSNS for chemical metal cleaning
wastes.) For additional information regarding the pollutants that may
be present in nonchemical metal cleaning wastes, see the 1974
Development Document for Effluent Limitations Guidelines and New Source
Performance Standards for the Steam Electric Power Generating Point
Source Category. Based on the information developed for the previous
rulemakings for the steam electric power generating ELGs and the data
from the industry survey, EPA identified 4 pollutants of concern for
nonchemical metal cleaning wastes, including: 2 conventional pollutants
(TSS and oil and grease); 1 toxic pollutant (copper); and 1
nonconventional pollutant (iron).
See Section 6 of the Technical Development Document for Proposed
Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category (TDD)--EPA 821-R-13-002 for more
detailed information regarding pollutants of concern.
B. Selection of Pollutants for Regulation Under BAT/NSPS
The pollutants of concern identified for each wastestream
represents those pollutants that are present at treatable
concentrations in a significant percentage of untreated wastewater
samples from that wastestream. Effluent limits and monitoring for all
pollutants of concern is not necessary to ensure that the pollutants
are adequately controlled because many of the pollutants originate from
similar sources, have similar treatabilities, and are removed by
similar mechanisms. Because of this, it may be sufficient to establish
effluent limits for one pollutant as a surrogate or indicator pollutant
that ensures the removal of other pollutants of concern. In addition,
establishing effluent limits may not be appropriate for certain
pollutants of concern when the technology used as the basis for the
effluent limits is not reliably effective at removing the pollutant(s).
From the list of pollutants of concern identified for each
wastestream, EPA selected a subset of pollutants for establishing
numeric effluent limitations. EPA considered the following factors in
selecting regulated pollutants from the list of pollutants of concern:
The pollutant was detected in the untreated wastewater at
treatable levels in a significant number of samples.
The pollutant is not used as a treatment chemical in the
treatment technology that serves as a basis for the proposed regulatory
option. EPA eliminated pollutants associated with treatment system
additives because regulating these pollutants could interfere with
efforts to optimize treatment system operation.
The pollutant is effectively treated by the treatment
technology that serves as the basis for the proposed regulatory option.
EPA excluded all pollutants for which the treatment technology was
ineffective (e.g., pollutant concentrations remained approximately
unchanged or increased across the treatment system).
The pollutant is not adequately controlled through the
regulation of another pollutant.
Because the criteria for identifying regulated pollutants from the
list of pollutants of concern depends on the treatment technology that
serves as the basis for a proposed regulatory option, EPA may regulate
a different subset of pollutants for a single wastestream under
different regulatory options.
For the proposed options for this rulemaking (described below in
Section VIII), EPA identified six pollutants for potential regulation
for FGD wastewater: oil and grease, TSS, arsenic, mercury, nitrate/
nitrite, and selenium. For leachate, EPA identified four potential
pollutants for regulation: oil and grease, TSS, arsenic and mercury.
For fly ash discharges, bottom ash, and FGMC wastewater, under some
proposed options, EPA is proposing to establish zero discharge
limitations, which in effect directly control all pollutants of
concern. For other proposed options that would not require zero
pollutant discharge, EPA identified two potential pollutants for
regulation: oil and grease and TSS for nonchemical metal cleaning
wastes, EPA identified four pollutants for potential regulation (TSS,
oil and grease, copper, and iron). EPA identified four pollutants for
regulation for gasification wastewater: arsenic, mercury, selenium, and
TDS.
See Section 6.7 of the Technical Development Document for Proposed
Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category (TDD)--EPA 821-R-13-002 for more
information about the pollutants of concern and EPA's rationale for
selecting the pollutants proposed for regulation.
C. Methodology for the POTW Pass Through Analysis (PSES/PSNS)
Section 307(b) and (c) of the CWA requires EPA to promulgate
pretreatment standards for pollutants that are not susceptible to
treatment by POTWs or which would interfere with the operation of
POTWs. EPA looks at a number of factors in selecting the technology
basis for pretreatment standards for existing and new sources. These
factors are generally the same as those considered in establishing BAT
and NSPS, respectively. However, unlike direct dischargers whose
wastewater will receive no further treatment once it leaves the
facility, indirect dischargers send their wastewater to POTWs for
further treatment. As such, EPA must also determine that a pollutant is
not susceptible to treatment at a POTW or would interfere with POTW
operations.
Before establishing PSES/PSNS for a pollutant, EPA examines whether
the pollutant ``passes through'' a POTW to waters of the U.S. or
interferes with the POTW operation or sludge disposal practices. In
determining whether a pollutant would pass through POTWs, EPA generally
compares the percentage of a pollutant removed by well-operated POTWs
performing secondary treatment
[[Page 34457]]
to the percentage removed by BAT/NSPS treatment systems. A pollutant is
determined to pass through POTWs when the median percentage removed
nationwide by well-operated POTWs is less than the median percentage
removed by direct dischargers complying with BAT/NSPS effluent
limitations and standards. Pretreatment standards are established for
those pollutants regulated under BAT/NSPS that pass through POTWs to
waters of the U.S. or interfere with POTW operations or sludge disposal
practices. This approach to the definition of pass-through satisfies
two competing objectives set by Congress: (1) That standards for
indirect dischargers be equivalent to standards for direct dischargers,
and (2) that the treatment capability and performance of POTWs be
recognized and taken into account in regulating the discharge of
pollutants from indirect dischargers.
For this proposed rule, EPA conducted a pass through analysis for
the technology basis for each wastestream for each regulatory option
presented below in Section VII.C. For those wastestreams and regulatory
options for which EPA is proposing zero discharge of pollutants, EPA
set the percentage removed by the technology basis at 100 percent. EPA
did not conduct its traditional pass-through analysis for these
wastestreams (e.g., fly ash transport water, bottom ash transport
water, and flue gas mercury control wastewater) because limitations for
these wastestreams for direct dischargers would consist of no discharge
of process wastewater pollutants to waters of the U.S., and therefore,
all pollutants would ``pass through'' the POTW for these wastestreams.
During the 1976 development of pretreatment standards for chemical
metal cleaning wastes, EPA selected pollutants for regulation based on
two criteria:
The pollutant has the potential to harm the POTW (e.g.,
impair the activity of the biological treatment system); or
The pollutant has the potential to harm the receiving
water (i.e., if the pollutant is not removed or is removed inadequately
by the POTW).
Using these criteria, the Agency determined it was appropriate to
establish pretreatment standards for the discharge of copper in
chemical metal cleaning wastes. For this rulemaking, EPA believes that,
as is the case for copper in chemical metal cleaning wastes, the copper
present in nonchemical metal cleaning wastes would pass through the
POTW.
For FGD wastewater, leachate, and gasification wastewater, EPA
determined the percentage removed for the pollutants by the technology
basis using the same data sources used to determine the long-term
averages for each set of limitations (see Section 13 of the TDD).\18\
As it has done for other rulemakings, EPA determined the percentage
removed by well-operated POTWs performing secondary treatment from one
of two data sources:
---------------------------------------------------------------------------
\18\ For FGD wastewater and leachate, this discussion applies to
those regulatory options that would provide additional control for
discharges of toxics like arsenic, mercury and selenium.
---------------------------------------------------------------------------
Fate of Priority Pollutants in Publicly Owned Treatment
Works, September 1982, EPA 440/1-82/303 (50 POTW Study); and
National Risk Management Research Laboratory (NRMRL)
Treatability Database, Version 5.0, February 2004 (formerly called the
Risk Reduction Engineering Laboratory (RREL) database).
The 50 POTW study presents data on the performance of 50 POTWs
achieving secondary treatment in removing toxic pollutants. When data
for a pollutant were available from the 50 POTW Study, EPA used that
data. When data for pollutants were not available from the 50 POTW
Study, EPA used NRMRL data. The NRMRL treatability database provides
information on removals obtained by various treatment technologies for
a variety of wastewater sources. Therefore, where EPA used data from
the NRMRL treatability database, it used only data from the treatment
of domestic and industrial wastewater using technologies representative
of secondary treatment. For a more detailed discussion of how EPA
performed its removal analysis, see Section 11 of the TDD.
With a few exceptions, EPA performs a POTW pass-through analysis
for pollutants selected for regulation for BAT/NSPS for each
wastestream of concern and for each regulatory option. The exception is
for conventional pollutants such as BOD5, TSS, and oil and
grease. POTWs are designed to treat these conventional pollutants;
therefore, they are not considered to pass through.
Section VIII below summarizes the results of the pass through
analysis. All of the pollutants proposed for regulation under BAT/NSPS
(except for conventional pollutants and iron found in nonchemical metal
cleaning wastes) were found to pass through and, therefore, were
selected for regulation under PSES/PSNS.
VIII. Proposed Regulation
A. Regulatory Options
1. BPT/BCT
EPA is not proposing to revise the BPT effluent guidelines or
establish BCT effluent guidelines in this notice because the same
wastestreams would be controlled at the proposed BAT/BADCT (NSPS) level
of control. EPA is proposing to remove FGD wastewater, FGMC wastewater,
gasification wastewater, and leachate from the definition of low-volume
wastes. As a result, EPA is making a structural adjustment to the text
of the regulation at 40 CFR part 423 to add paragraphs that list these
four wastestreams by name, along with their applicable effluent
limitations. The reformatted regulatory text for these four
wastestreams includes BPT effluent limits, which are the same as the
current BPT effluent limits for low volume wastes.
2. Description of the BAT/NSPS/PSES/PSNS Options
EPA is proposing to revise or establish BAT, BADCT (NSPS), PSES,
and PSNS that may apply to discharges of seven wastestreams: FGD
wastewater, fly ash transport water, bottom ash transport water,
combustion residual leachate, nonchemical metal cleaning wastes, and
wastewater from FGMC systems and gasification systems. In Section VI of
this preamble and in the TDD, EPA describes the treatment technologies
and operational practices that it reviewed during the development of
this proposed rule. From these, EPA identified a subset of technologies
(treatment processes and operational practices) that were most
promising as candidate BAT/BADCT options. In this proposal, EPA is
presenting eight main regulatory options (i.e., Option 1, Option 3a,
Option 2, Option 3b, Option 3, Option 4a, Option 4, and Option 5) that
represent different levels of pollutant removal associated with
different wastewater streams (i.e., each succeeding option from Option
1 to Option 5 would achieve more reduction in discharges of pollutants
to waters of the U.S). Table VIII-1 summarizes the eight main
regulatory options, which are described in the paragraphs below.
As discussed further below, EPA is also proposing to add provisions
to the ELGs that would prevent facilities from circumventing applicable
ELGs. The proposed provisions would clarify the acceptable conditions
for discharge of reused process wastewater and establish effluent
monitoring requirements.
[[Page 34458]]
EPA is considering establishing BMPs that would apply to surface
impoundments (i.e., ponds) that receive, store, dispose of, or are
otherwise used to manage coal combustion residuals including FGD
wastes, fly ash, bottom ash (which includes boiler slag), leachate, and
other residuals associated with the combustion of coal to prevent
uncontrolled discharges from these impoundments as described below in
the paragraph titled, ``BMPs for CCR Surface Impoundments.''
As part of its consideration of technological availability and
economic achievability for all regulatory options, EPA considered the
magnitude and complexity of process changes and new equipment
installations that would be required at facilities to meet the
requirements of the rule. As described further below, EPA proposes that
certain limitations and standards being proposed today for existing
sources would not apply until July 1, 2017 (approximately three years
from the effective date of this rule).
EPA is also considering establishing, as part of the BAT for
existing sources, a voluntary incentive program that would provide more
time for plants to implement the proposed BAT requirements if they
adopt additional process changes and controls that would provide
significant environmental protections beyond those achieved by the
preferred options in this proposed rule. As described further below,
power plants would be granted two additional years (beyond the time
described above in the preceding paragraph) if they also dewater, close
and cap all CCR surface impoundments at the facility (except combustion
residual leachate impoundments), including those surface impoundments
located on non-adjoining property that receive CCRs from the facility.
A power plant participating in the voluntary incentive program could
continue to operate surface impoundments for which combustion residual
leachate was the only type of CCR solids or wastewater contained in the
impoundment. Power plants would be granted five additional years
(beyond the time described above in the preceding paragraph) if they
eliminate discharges of all process wastewater to surface waters, with
the exception of cooling water discharges.
Table VIII-1--Steam Electric Main Regulatory Options
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Technology basis for the main BAT/NSPS/PSES/PSNS regulatory options
Wastestreams ---------------------------------------------------------------------------------------------------------------------------------------------------------------
1 3a 2 3b 3 4a 4 5
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
FGD Wastewater.................. Chemical BPJ Determination. Chemical Chemical Chemical Chemical Chemical Chemical
Precipitation. Precipitation + Precipitation + Precipitation + Precipitation + Precipitation + Precipitation +
Biological Biological Biological Biological Biological Evaporation
Treatment. Treatment for Treatment. Treatment. Treatment.
units at a
facility with a
total wet-
scrubbed capacity
of 2,000 MW and
more; BPJ
determination for
<2,000 MW.
Fly Ash Transport Water......... Impoundment (Equal Dry handling...... Impoundment (Equal Dry handling...... Dry handling...... Dry handling...... Dry handling...... Dry handling
to BPT). to BPT).
Bottom Ash Transport Water...... Impoundment (Equal Impoundment (Equal Impoundment (Equal Impoundment (Equal Impoundment (Equal Dry handling/ Dry handling/ Dry handling/
to BPT). to BPT). to BPT). to BPT). to BPT). Closed loop (for Closed loop. Closed loop
units >400 MW);
Impoundment
(Equal to
BPT)(for units
<=400 MW).
Combustion Residual Leachate.... Impoundment (Equal Impoundment (Equal Impoundment (Equal Impoundment (Equal Impoundment (Equal Impoundment (Equal Chemical Chemical
to BPT). to BPT). to BPT). to BPT). to BPT). to BPT). Precipitation. Precipitation
FGMC Wastewater................. Impoundment (Equal Dry handling...... Impoundment (Equal Dry handling...... Dry handling...... Dry handling...... Dry handling...... Dry handling
to BPT). to BPT).
Gasification Wastewater......... Evaporation....... Evaporation....... Evaporation....... Evaporation....... Evaporation....... Evaporation....... Evaporation....... Evaporation
Nonchemical Metal Cleaning Chemical Chemical Chemical Chemical Chemical Chemical Chemical Chemical
Wastes \19\. Precipitation. Precipitation. Precipitation. Precipitation. Precipitation. Precipitation. Precipitation. Precipitation
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------
\19\ As described in Section VIII, EPA is proposing to exempt
from new copper and iron BAT limitations any existing discharges of
nonchemical metal cleaning wastes that are currently authorized
without iron and copper limits.
---------------------------------------------------------------------------
FGD Wastewater. Addressing the variety of pollutants present in FGD
wastewater typically requires several stages of treatment to remove the
suspended solids, particulate and dissolved metals, and other
pollutants present. Historically, power plants have relied on surface
impoundments to treat FGD wastewater because NPDES permits generally
focused on controlling suspended solids for this wastestream. Surface
impoundments are the technology basis for the current BPT effluent
limits (last revised in 1982) for steam electric power plants. In
recent years, physical/chemical treatment systems and other more
advanced systems have become more widely used as effluent limits for
metals and other pollutants have been included in permits, in nearly
all cases driven by the need to utilize such technologies to meet water
quality-based effluent limits (WQBELs) established to meet applicable
water quality standards in
[[Page 34459]]
the receiving waters. At present, a number of steam electric plants
either use chemical precipitation or chemical precipitation and
biological treatment to control discharges of FGD wastes. However,
surface impoundments continue to be the predominant technology used to
treat FGD wastewater, with 54 percent of plants that discharge FGD
wastewater relying on this technology alone (i.e., not including the
plants that use surface impoundments as pretreatment for more advanced
treatment). In addition, it is common for plants to commingle the
surface impoundment FGD effluent with wastestreams of significantly
higher flows (e.g., ash transport water and cooling water) because the
higher-flow wastestreams dilute the FGD wastewater so that the
resulting pollutant concentrations in the combined wastestream do not
exceed the applicable water quality-based effluent limitations.
Surface impoundments use gravity to remove solid particles (i.e.,
suspended solids) from the wastewater. Metals in FGD wastewater are
present in both soluble (i.e., dissolved) and particulate form. Some
metals, such as arsenic, are often present mostly in particulate form;
these usually can be removed to a substantial degree by a well-operated
settling process that has a sufficiently long residence time. However,
other pollutants, such as selenium, boron, and magnesium, are present
mostly in soluble form and are not effectively and reliably removed by
wastewater surface impoundments. For metals present in both soluble and
particulate forms (such as mercury), surface impoundments will not
effectively remove the dissolved fraction. Furthermore, the conditions
present in some surface impoundments can create chemical conditions
(e.g., low pH) that convert particulate forms of metals to soluble
forms, which would not be removed by the gravity settling process in
the surface impoundment. Additionally, EPRI (a technical research
organization funded by the electric power industry) has reported that
adding FGD wastewater to surface impoundments used to treat ash
transport water (i.e., ash ponds) may reduce the settling efficiency in
the impoundments due to gypsum particle dissolution, thus increasing
the effluent TSS concentrations. EPRI has also reported that the FGD
wastewater includes high loadings of volatile metals, which can
increase the solubility of metals in surface impoundments, thereby
leading to increased levels of dissolved metals and resulting in higher
concentrations of metals in the discharge from surface impoundments.
During the summer, some surface impoundments become thermally
stratified. When this occurs, the top layer of the impoundment is
warmer and contains higher levels of dissolved oxygen, whereas the
bottom layer of the impoundment is colder and can have significantly
lower levels of oxygen and may develop anoxic conditions. Typically,
during fall, as the air temperature decreases, the upper layer of the
impoundment becomes cooler and denser, thereby sinking and causing the
entire volume of the impoundment to circulate. Solids that have
collected at the bottom of the impoundment may become resuspended due
to such mixing, increasing the concentrations of pollutants discharged
during the turnover period. Seasonal turnover effects largely depend
upon the size and configuration of the surface impoundment. Smaller,
and especially shallow, surface impoundments likely do not experience
turnover because they do not have physical characteristics that promote
thermal stratification. However, some surface impoundments are large
(e.g., greater than 300 acres) and deep (e.g., greater than 10 meters
deep) and likely experience some degree of turnover.
Technologies more advanced than surface impoundments exist and that
are more effective at removing both soluble (i.e., dissolved) and
particulate forms of metals, as well as other pollutants such as
nitrogen compounds and TDS. Because many of the pollutants of concern
for FGD wastewater are present in dissolved form and would not be
removed by surface impoundments, and because of the relatively large
mass loads of these pollutants (e.g., selenium, dissolved mercury)
discharged by the FGD wastestream, EPA explored other technologies that
would be more effective at removing these pollutants of concern and is
co-proposing three options that would include such technologies.
However, for reasons discussed in Section VII.A.3, EPA is also co-
proposing options under which some or all facilities would continue,
for the purposes of the ELGs, to be subject to the BPT requirements
based on surface impoundments for treatment of FGD wastewater. Under
these options, BAT would be left to a site-specific determination. For
the reasons discussed above and in Section VIII.A.3, EPA also does not
believe that surface impoundments represent best available demonstrated
control technology for controlling pollutants in FGD wastewater.
Therefore, none of the regulatory options for NSPS presented in this
proposal are based on the performance of surface impoundments for FGD
wastewater.
The technology basis for the effluent limitations and standards for
FGD wastewater in Option 1 is physical/chemical treatment consisting of
the following: Chemical precipitation/coprecipitation (employing the
combination of hydroxide precipitation, iron coprecipitation, and
sulfide precipitation). Option 1 also incorporates the use of flow
minimization for plants with high FGD discharge flow rates (i.e.,
greater than 1,000 gpm) and FGD system metallurgy and operating
practices that can accommodate an increase in chlorides (e.g., scrubber
systems constructed of non-metallic materials or corrosion-resistant
metal alloys, or systems operating with absorber chloride
concentrations substantially below the design chloride limit). The flow
minimization at these plants would be achieved by either reducing the
FGD purge rate or recycling a portion of their FGD wastewater.
Physical/chemical treatment (i.e., chemical precipitation) is used
to remove metals and other pollutants from wastewater. Chemicals are
added to the wastewater in a series of reaction tanks to convert
soluble metals to insoluble metal hydroxide or metal sulfide compounds,
which precipitate from solution and are removed along with other
suspended solids. An alkali, such as hydrated lime, is typically added
to adjust the pH of the wastewater to the point where metals
precipitate out as metal hydroxides (typically referred to as hydroxide
precipitation). Chemicals such as ferric chloride are often added to
the system to increase the removal of certain metals through iron
coprecipitation. The ferric chloride also acts as a coagulant, forming
a dense floc that enhances settling of the metal precipitate in the
downstream clarification stage. Coagulants and flocculants are often
added to facilitate the settling and removal of the newly formed
solids. Plants trying to increase removals of mercury and other metals
will also include sulfide addition (e.g., organosulfide) as part of the
process. Adding sulfide chemicals in addition to hydroxide
precipitation provides even greater reductions of heavy metals due to
the very low solubility of metal sulfide compounds, relative to metal
hydroxides. Sulfide precipitation is widely used in Europe and multiple
locations in the United States have installed this technology. Forty
U.S. power plants (34 percent of plants
[[Page 34460]]
discharging FGD wastewater) include physical/chemical treatment as part
of the FGD wastewater treatment system; more than half of these plants
(28 percent of plants discharging FGD wastewater) use both hydroxide
and sulfide precipitation in the process.
The technology basis for the effluent limitations and standards for
FGD wastewater in Options 2, 3b (for units located at facilities with a
total wet-scrubbed capacity of 2,000 MW or more) \20\, 3, 4a, and 4 is
chemical precipitation/coprecipitation (the same technology basis under
Option 1) used in combination with anoxic/anaerobic biological
treatment designed to optimize removal of selenium. As is the case for
Option 1, these BAT options also incorporate the use of flow
minimization for plants with high FGD discharge flow rates (i.e.,
greater than 1,000 gpm) and FGD system metallurgy and operating
practices that can accommodate an increase in chlorides. The flow
minimization at these plants would be achieved by either reducing the
FGD purge rate or recycling a portion of their FGD wastewater.
---------------------------------------------------------------------------
\20\ This value is calculated by summing the nameplate capacity
for all of the units that are serviced by wet FGD systems.
---------------------------------------------------------------------------
Physical/chemical treatment systems are capable of achieving low
effluent concentrations of various metals and the sulfide addition is
particularly important for removing mercury; however, this technology
is not effective at removing selenium, nitrogen compounds, and certain
metals that contribute to high concentrations of TDS in FGD wastewater
(e.g., bromides, boron). Six power plants in the U.S. are operating FGD
treatment systems that include a biological treatment stage designed to
substantially reduce nitrogen compounds and selenium.\21\ Other
industries have also used this technology to remove selenium and other
pollutants. These systems use anoxic/anaerobic bioreactors optimized to
remove selenium from the wastewater. The bioreactor alters the form of
selenium, reducing selenate and selenite to elemental selenium, which
is then captured by the biomass and retained in treatment system
residuals. The conditions in the bioreactor are also conducive to
forming metal sulfide complexes to facilitate additional removals of
mercury, arsenic, and other metals. The information in the record for
this proposed rule demonstrates that the amount of mercury and other
pollutants removed by the biological treatment stage of the treatment
system, above and beyond the amount of pollutants removed in the
chemical precipitation treatment stage preceding the bioreactor, can be
substantial. In addition, the anoxic conditions in the bioreactor
remove nitrates by denitrification and, if necessary, the biological
processes can be modified to include a step to nitrify and remove
ammonia. Four of these six plants precede the biological treatment
stage with physical/chemical treatment; thus, the entire system is
designed to remove suspended solids, particulate and dissolved metals,
soluble and insoluble forms of selenium, and nitrate and nitrite forms
of nitrogen. The other two plants operating anoxic/anaerobic
bioreactors to remove selenium precede the biological treatment stage
with surface impoundments instead of chemical precipitation. While the
treatment systems at these two plants would be less effective at
removing metals (including many dissolved metals) than the plants
utilizing chemical pretreatment, they nevertheless show the efficacy of
biological treatment for removing selenium and nitrate/nitrite from FGD
wastewater. Three percent of the plants discharging FGD wastewater use
chemical precipitation followed by anaerobic biological treatment to
treat this wastewater, which is the technology basis for Options 2, 3b
(for units located at facilities with a total wet-scrubbed capacity of
2,000 MW or more), 3, 4a, and 4.
---------------------------------------------------------------------------
\21\ A seventh plant is scheduled to begin operating a
biological treatment system for selenium removal next year. Another
plant is installing a similar treatment system to remove selenium in
discharges of combustion residual leachate.
---------------------------------------------------------------------------
The technology basis for the effluent limitations and standards for
FGD wastewater in Option 5 is chemical precipitation/coprecipitation
used in combination with vapor compression evaporation. Physical/
chemical treatment systems can achieve low effluent concentrations for
a number of pollutants, and reduce concentrations even further when
combined with biological treatment systems, as described above and in
the TDD. However, these technologies have not been effective at
removing substantial amounts of boron and pollutants such as sodium and
bromides that contribute to high concentrations of TDS. Another FGD
wastewater treatment technology that can address these more
recalcitrant pollutants, as well as removing the pollutants treated by
physical/chemical and biological technologies, is vapor-compression
evaporation. This technology uses an evaporator to produce a
concentrated wastewater stream and a reusable distillate stream. The
concentrated wastewater stream is either disposed of or further
processed to produce a solid by-product and additional distillate. The
plant can reuse the distillate stream as makeup water. Two U.S. plants
and four Italian plants are operating this technology to treat FGD
wastewater from their coal-fired generating units.\22\
---------------------------------------------------------------------------
\22\ A third U.S. plant is currently installing a vapor-
compression evaporation system to treat the FGD wastewater.
---------------------------------------------------------------------------
For Option 3a and Option 3b (for units located at facilities with a
total wet-scrubbed capacity of less than 2,000 MW), EPA is proposing
not to characterize a technology basis for effluent limitations and
standards applicable to discharges of pollutants in FGD wastewater at
this time. As illustrated above, there is a wide range of technologies
currently in use for reducing pollutant discharges associated with FGD
wastewater, and research continues in the development of additional
technologies to treat FGD wastewater (see Section 7.1.7 of the TDD for
more information on emerging technologies). The more advanced
technologies (those that reduce the most pollutants) reflect recent
innovations in the area of treatment of FGD wastewater. EPA expects
this trend to continue and, therefore, under Option 3a and Option 3b
(for units located at facilities with a total wet-scrubbed capacity of
less than 2,000 MW), effluent limitations representing BAT for
discharges of FGD wastewater would be determined on a site-specific BPJ
basis. Under Options 3a and Option 3b (for units located at facilities
with a total wet-scrubbed capacity of less than 2,000 MW), pretreatment
program control authorities would need to develop local limits to
address the introduction of pollutants in FGD wastewater by steam
electric plants to the POTWs that cause pass through or interference,
as specified in 40 CFR 403.5(c)(2).
As described below in this section of the preamble, EPA is
proposing that certain limitations and standards being proposed today
for existing sources would apply to discharges of FGD wastewater
generated on or after the date established by the permitting authority
that is as soon as possible within the next permit cycle after July 1,
2017. FGD wastewater generated prior to that date (i.e., ``legacy''
wastewater) from existing direct dischargers would remain subject to
the existing BPT effluent limits. For indirect dischargers, EPA is
proposing that PSES for FGD wastewater would apply to FGD wastewater
generated after a date determined by the control authority that is as
soon as possible beginning July 1,
[[Page 34461]]
2017. EPA considered subjecting legacy FGD wastewater to the proposed
BAT and PSES requirements. However, as explained above, FGD wastewater
and its associated pollutants are typically sent to surface
impoundments for treatment prior to discharge. These surface
impoundments often contain other plant wastewaters, such as fly ash or
bottom ash transport water, coal pile runoff, and/or low volume wastes.
According to data provided by the industry survey, 78 percent of
surface impoundments that receive FGD wastewater also receive fly ash
and/or bottom ash transport water. EPA does not have the data to
demonstrate that the technologies identified above represent BAT for
legacy FGD wastewater. As such, EPA is not proposing BAT requirements
associated with discharges of legacy FGD wastewater generated prior to
the date established by the permitting authority (for direct
dischargers) or control authority (for indirect dischargers). As
proposed today, discharges of legacy FGD wastewater by existing direct
dischargers would remain subject to the existing BPT effluent limits;
however, under some of the proposed options, EPA is also considering
setting the BAT effluent limitations for legacy FGD wastewater that has
not been mixed with non-legacy wastes equal to the existing BPT
effluent limits. See Section XVI for additional information.
Fly Ash Transport Water. Under Options 1 and 2, BAT effluent
limitations for fly ash transport water would be set equal to the
current BPT effluent limitations, based on the technology of gravity
settling in surface impoundments to remove suspended solids. The
current effluent guidelines for existing sources include BPT effluent
limits for the allowable levels of TSS and oil and grease in discharges
of fly ash transport water. The BPT effluent limits are based on the
performance of surface impoundments, which when well-designed and well-
operated can effectively remove suspended solids, including pollutants
such as particulate forms of certain metals when associated with the
suspended solids.
Under Options 3a, 3b, 3, 4a, 4, and 5, EPA would establish ``zero
discharge'' effluent limitations and standards for discharges of
pollutants in fly ash transport water, based on the use of dry fly ash
handling technologies. The dry handling technologies for fly ash are
described above in Section VI of this preamble and in the TDD for the
proposed rule. Although surface impoundments can be effective at
removing particulate forms of certain metals and other pollutants, they
are not designed for, nor are they effective at, removing other
pollutants of concern such as dissolved metals and nutrients. The
concentrations of pollutants that remain in the ash impoundment
effluent following gravity settling, in combination with the large
volumes of fly ash transport water discharged to surface waters (2.4
MGD on average per discharging plant), results in a large mass loading
of pollutants of concern being discharged from surface impoundments.
Furthermore, as described in Section VI, surface impoundments can be
susceptible to seasonal turnover that degrades pollutant removal
efficacy, and co-managing FGD and ash wastes in the same impoundments
can lead to increased pollutant discharges.
Dry handling technologies are the technology basis for the current
fly ash NSPS/PSNS requirements, which were promulgated in 1982. All
generating units built since then have been subject to a ``zero
discharge'' standard. Some existing units have also converted to dry
handling technologies. Due to the NSPS discharge standard or economic
or operational factors, approximately 66 percent of coal- and petroleum
coke-fired generating units that produce fly ash currently operate dry
fly ash transport systems, while another 15 percent operate both wet
and dry fly ash transport systems. The remaining 19 percent operate
only wet fly ash transport systems. In cases where a unit has both wet
and dry handling operations, the wet handling system is typically used
as a backup to the dry system. Effluent limitations and standards based
on dry ash handling would completely eliminate the discharge of
pollutants in fly ash transport water.
EPA considered basing one or more regulatory options for fly ash
transport water on chemical precipitation treatment technology, with
numeric effluent limits for discharges of the wastestream to surface
waters. EPA has not identified any facilities using this treatment
technology to treat fly ash transport water, although EPA has reviewed
two literature sources that describe laboratory- or pilot-scale tests
using the technology. Upon reviewing the discharge flow rates for fly
ash transport water, however, EPA determined that the costs associated
with treatment using chemical precipitation were higher than the cost
of the dry handling technology upon which Options 3a, 3b, 3, 4a, 4, and
5 are based, despite being less effective at removing pollutants. Since
the costs for chemical precipitation treatment are higher than the cost
for converting to dry handling technologies, and chemical precipitation
removes fewer pollutants, EPA did not include chemical precipitation
treatment as part of the regulatory options for fly ash in this
proposed rule. See DCN SE03869.
As described below in this section of the preamble, EPA is
proposing that the limitations for existing sources based on Options
3a, 3b, 3, 4a, 4, or 5 would apply to discharges of fly ash transport
water generated after the date established by the permitting authority
that is as soon as possible within the next permit cycle after July 1,
2017. For indirect dischargers, EPA is proposing that PSES for fly ash
would apply to the fly ash transport water generated after a date
determined by the control authority that is as soon as possible
beginning July 1, 2017. Fly ash transport water generated by existing
direct dischargers prior to that date (i.e., ``legacy'' wastewater)
would remain subject to the existing BPT effluent limits. EPA
considered subjecting legacy fly ash transport water (i.e., the fly ash
transport water generated prior to the date established by the
permitting authority, as described above) to the proposed BAT zero
discharge requirement. As explained above, currently fly ash transport
wastewater and the associated pollutants are sent to surface
impoundments for treatment prior to discharge. The technology basis
identified above for the proposed zero discharge requirement eliminates
the generation of the fly ash wastewater but does not eliminate fly ash
transport wastewater that has already been transferred to a surface
impoundment. Furthermore, the technologies identified as the basis for
fly ash transport water discharge requirements have not been
demonstrated for the legacy fly ash transport wastewater that has
already been generated. As such, EPA is not proposing BAT or PSES
requirements for discharges of legacy fly ash transport water generated
prior to the date established by the permitting authority or control
authority. As proposed today, discharges of legacy fly ash transport
water by existing direct dischargers would remain subject to the
existing BPT effluent limits; however, EPA is also considering whether
to set the BAT effluent limitations for legacy fly ash transport water
equal to the existing BPT effluent limits. See Section XVI for
additional information.
Bottom Ash Transport Water. Under Options 1, 3a, 2, 3b, 3, and 4a
(for units less than or equal to 400 MW), effluent limitations and
standards for bottom ash transport water would be set equal to the
current BPT effluent limitations,
[[Page 34462]]
based on the technology of gravity settling in surface impoundments to
remove suspended solids. The 1982 effluent guidelines for existing
sources include BPT effluent limits for the allowable levels of TSS and
oil and grease in discharges of bottom ash transport water. The BPT
effluent limits are based on the performance of surface impoundments,
which when well-designed and well-operated can effectively remove
suspended solids, including pollutants such as particulate forms of
certain metals when associated with the suspended solids.
Although surface impoundments can be effective at removing
particulate forms of metals and other pollutants, they are not designed
for nor are they effective at removing other pollutants of concern such
as dissolved metals and nutrients. The concentrations of pollutants
that remain in the wastestream at the ash impoundment effluent, in
combination with the large volumes of bottom ash transport water
discharged to surface waters, results in a large mass loading of
pollutants of concern being discharged from surface impoundments.
Effluent limitations and standards based on the technologies used as
the basis for Options 4a (for units more than 400 MW), 4, and 5 would
completely eliminate the discharge of pollutants in bottom ash
transport water.
Under Options 4a (for units more than 400 MW), 4, and 5, EPA would
establish ``zero discharge'' effluent limitations and standards for
discharges of pollutants in bottom ash transport water, based on either
using bottom ash handling technologies that do not require transport
water or managing a wet-sluicing bottom ash handling system so that it
does not discharge bottom ash transport water or pollutants associated
with the bottom ash transport water. These technologies for handling
bottom ash are described above in section VI of this preamble and in
the TDD for the proposed rule. About 80 percent of coal- and petroleum
coke-fired units generating bottom ash operate wet bottom ash transport
systems, while approximately 20 percent operate systems that eliminate
the use of transport water. Most, but not all, of the wet bottom ash
transport systems discharge to surface waters. In cases where a plant
has both wet and dry handling operations, the wet handling system is
typically used as a backup to the dry system. In the case of bottom ash
handling systems, the term ``dry'' is typically used to refer to a
process that does not use water as the transport medium to sluice the
bottom ash to a CCR impoundment. In some cases, a ``dry'' bottom ash
system may be entirely dry and avoid all use of water. Many dry bottom
ash systems, however, include a water bath at the bottom of a boiler in
which the bottom ash is dropped and cooled, and then the bottom ash is
mechanically dragged out of the boiler along a conveyor belt and
deposited in a pile adjacent to the building housing the boiler. The
bottom ash conveyed out of the water bath will be damp because the ash
particles retain some moisture from the water bath and small volumes of
water will typically drain from the standing bottom ash pile. The water
draining from the pile is usually collected in a sump and either
returned to the water bath below the boiler or managed as low volume
waste. Such mechanical drag systems are considered as one available
technology that may be used to achieve proposed limitations and
standards under Options 4a (for units >400 MW), 4, and 5. Other
technologies serving as the basis for limitations and standards
proposed under Options 4a (for units >400 MW), 4, and 5 are completely
dry bottom ash systems, remote mechanical drag systems, and
impoundment-based systems that are managed to eliminate the discharge
of all bottom ash transport water and the associated pollutants.
In developing the technologies that serve as the basis for the
regulatory options with respect to bottom ash transport water, EPA
considered basing one or more options on chemical precipitation
treatment technology, with numeric effluent limitations or standards
for discharges of the wastestream to surface waters. Upon reviewing the
discharge flow rates for bottom ash transport water, however, EPA
determined that the costs associated with treatment were comparable to
the cost of the technologies upon which Options 4a (for units more than
400 MW), 4, and 5 are based, despite being less effective at removing
pollutants. Since the costs for chemical precipitation treatment were
found to be higher than the cost for converting to dry handling or
closed loop technologies, and the treatment technology removes fewer
pollutants, EPA did not include chemical precipitation treatment as
part of the regulatory options for bottom ash in this proposed rule.
See DCN SE03869.
As described below in this section of the preamble, EPA is
proposing that certain BAT limitations for existing sources under
Options 4a (for units more than 400 MW), 4, or 5 would apply to
discharges of bottom ash transport water generated after the date
established by the permitting authority or control authority that is as
soon as possible within the next permit cycle after July 1, 2017. For
indirect dischargers, EPA is proposing that PSES for bottom ash
transport water would apply to bottom ash transport water generated
after a date determined by the control authority that is as soon as
possible beginning July 1, 2017. Bottom ash transport water generated
by existing direct dischargers prior to that date (i.e., ``legacy''
wastewater) would remain subject to the existing BPT effluent limits.
EPA considered subjecting legacy bottom ash transport water (i.e., the
bottom ash transport water generated prior to the date established by
the permitting authority or control authority, as described above), to
the BAT and PSES zero discharge requirement considered under Options 4a
(for units more than 400 MW), 4, and 5. As explained above, currently,
bottom ash transport wastewater and the associated pollutants are sent
to surface impoundments for treatment prior to discharge. The
technology bases identified above for Options 4a (for units more than
400 MW), 4, and 5 eliminate the generation of the bottom ash wastewater
but do not eliminate bottom ash transport wastewater that has already
been transferred to a surface impoundment. The technologies identified
as the basis for bottom ash transport water discharge requirements
under Options 4a (for units more than 400 MW), 4, and 5 have not been
demonstrated for the legacy bottom ash transport wastewater that has
already been generated and do not represent BAT/PSES with respect to
legacy bottom ash wastewater. As such, under Options 4a (for units more
than 400 MW), 4, and 5 EPA would not establish BAT or PSES requirements
for discharges of legacy bottom ash transport water generated prior to
the date established by the permitting authority. As proposed today,
discharges of legacy bottom ash transport water by existing direct
dischargers would remain subject to the existing BPT effluent limits;
however, EPA is also considering whether to set the BAT effluent
limitations for legacy bottom ash transport water equal to the existing
BPT effluent limits. See Section XVI for additional information.
Combustion Residual Leachate. Under Options 1, 3a, 2, 3b, 3, and
4a, effluent limitations and standards for leachate from surface
impoundments and landfills containing combustion residuals would be set
equal to the current BPT effluent limitations, based on the technology
of gravity settling in surface impoundments to remove
[[Page 34463]]
suspended solids. Leachate is currently included under the definition
of low volume wastes, which are regulated by effluent limits for TSS
and oil and grease based on surface impoundments designed to remove
suspended solids. EPA is proposing that under Options 1, 3a, 2, 3b, 3,
and 4a, the rule would remove leachate from the definition of low
volume wastes at 40 CFR 423.11(b) and would set BAT effluent limits for
leachate equal to BPT limits for TSS and oil and grease (i.e., the
current effluent limits for low volume wastes).
The technology basis for effluent limitations and standards for
leachate under Options 4 and 5 is chemical precipitation/
coprecipitation. This same technology is the basis for BAT Option 1 for
FGD wastewater. Properly designed and operated surface impoundments can
effectively remove suspended solids, including pollutants such as
particulate forms of certain metals when associated with the suspended
solids. However, since surface impoundments are not designed for, nor
are they effective at, removing other pollutants of concern such as
dissolved metals, EPA used chemical precipitation/coprecipitation as
the technology basis for Options 4 and 5. Physical/chemical treatment
systems are capable of achieving low effluent concentrations of various
metals and are effective at removing many of the pollutants of concern
present in leachate discharges to surface waters. The pollutants of
concern in leachate are the same pollutants that are present in, and in
many cases are also pollutants of concern for, FGD wastewater, fly ash
transport wastewater, bottom ash transport water, and other combustion
residuals. This is to be expected since the leachate itself comes from
landfills and surface impoundments containing the combustion residuals
and those wastes are the source for the pollutants entrained in the
leachate. Given the similarities present among the different types of
wastewaters associated with combustion residuals, combustion residual
leachate will be similarly amenable to chemical precipitation
treatment. The treatability of pollutants such as arsenic and mercury
using chemical precipitation technology is also demonstrated by
technical information compiled for ELGs promulgated for other industry
sectors. See, e.g., the TDDs supporting the ELGs for the Landfills
Point Source Category (EPA-821-R-99-019) and the ELGs for the Metal
Products and Machinery Point Source Category (EPA-821-B-03-001).
However, as is the case when treating FGD wastewater, this technology
is not effective at removing selenium, boron and certain other
parameters that contribute to total dissolved solids (e.g., magnesium,
sodium).
EPA also considered developing a regulatory option that, for
leachate, would be based on the technology of chemical precipitation/
coprecipitation used in conjunction with anoxic/anaerobic biological
treatment. This is the same technology used as the basis for effluent
limitations and standards for FGD wastewater under Options 2, 3b (for
units at facilities with a total wet-scrubbed capacity of 2,000 MW or
more), 3, 4a, and 4. EPA has reviewed this technology as a potential
basis for effluent limitations and standards for leachate and the TDD
presents information about the compliance costs and pollutant removals
associated with this technology. The microorganisms used in the
bioreactors for the biological treatment technology for FGD wastewater
are resilient and have shown that they operate effectively under
varying conditions that occur in FGD system and the FGD wastewater
treatment system. However, leachate flows can be more variable than FGD
wastewater and, more importantly, may be too intermittent to facilitate
reliable and consistent biological treatment. Such variations are
easily accommodated in a chemical precipitation treatment system, but
may be difficult to manage in a biological treatment system reliant on
healthy and sustainable populations of microorganisms.
If EPA did finalize BAT effluent limits developed under Options 4
or 5 would (although it is not proposing such limits as a preferred
option today), EPA's intent is that these limits would apply to
discharges of leachate generated after the date established by the
permitting authority that is as soon as possible within the next permit
cycle after July 1, 2017. For indirect dischargers, PSES for leachate
would apply to leachate generated after a date determined by the
control authority that is as soon as possible beginning July 1, 2017.
Leachate generated by existing direct dischargers prior to that date
(i.e., ``legacy'' leachate wastewater) would remain subject to the
existing BPT effluent limits. EPA considered subjecting legacy leachate
wastewater to the proposed BAT and PSES limitations and standards.
However, although some plants use relatively small surface impoundments
to treat leachate and these impoundments would contain relatively small
volumes of legacy leachate wastewater, other plants send leachate to
relatively large surface impoundments that also contain other plant
wastewaters, such as fly ash or bottom ash transport water, cooling
water, and/or other low volume wastes. EPA does not have the data to
demonstrate that the technologies identified above represent BAT for
legacy combustion residual leachate. As such, EPA would not expect to
finalize BAT requirements associated with discharges of legacy
combustion residual leachate (i.e., the leachate generated prior to the
date established by the permitting authority or control authority). As
proposed today, discharges of legacy combustion residual leachate by
existing direct dischargers would remain subject to the existing BPT
effluent limits; however, EPA is also considering whether to set the
BAT effluent limitations for legacy combustion residual leachate that
has not been mixed with non-legacy wastes equal to the existing BPT
effluent limits. See Section XVI for additional information.
FGMC Wastewater. Under Options 1 and 2, effluent limitations and
standards for FGMC wastewater would be set equal to the current BPT
effluent limitations, based on the technology of gravity settling in
surface impoundments to remove suspended solids. Like leachate, FGMC
wastewater is currently included under the definition of low volume
wastes, with effluent limits for TSS and oil and grease based on
surface impoundments designed to remove suspended solids. EPA is
proposing that under all options, FGMC wastewater would be removed from
the definition of low volume wastes at 40 CFR 423.11(b). Under Options
1 and 2, BAT effluent limits for FGMC wastewater would be set equal to
BPT limits for TSS and oil and grease (i.e., the current effluent
limits for low volume wastes).
As discussed above in Section VI of this preamble, some plants
inject dry sorbents (e.g., activated carbon) into the flue gas stream
to reduce mercury emissions from the flue gas. Mercury adsorbs to the
sorbent particles, and these mercury-enriched sorbents are then removed
from the flue gas using a fabric filter or ESP. The sorbent can be
injected upstream of the primary particulate collector, in which case
the mercury-enriched sorbent is collected with the majority of the fly
ash. Alternatively, the sorbent can be injected downstream of the
primary particulate collector and collected with a much smaller amount
of fly ash (i.e., the fly ash that passed through the primary
collector) in a smaller, dedicated secondary particulate collector such
as a fabric filter. In either case, the plant collects the mercury-
[[Page 34464]]
enriched sorbents along with fly ash. Because of this, the BAT
technology basis for FGMC wastewater in this proposal is identical to
the BAT technology basis for fly ash.
Under Options 3a, 3b, 3, 4a, 4, and 5, EPA would establish ``zero
discharge'' effluent limitations and standards for discharges of
pollutants in FGMC wastewater based on using dry handling technologies
to store and dispose of fly ash without utilizing transport water. The
dry handling technologies that would be used for FGMC wastes are
identical to the dry fly ash handling technologies described above in
section VI of this preamble and in the TDD for the proposed rule.
Although surface impoundments can effectively remove particulate forms
of metals and other pollutants, they are not designed for nor are they
effective at removing other pollutants of concern such as dissolved
metals and nutrients. Effluent limits based on dry handling would
completely eliminate the discharge of pollutants in FGMC wastewater.
EPA is also aware of some plants that add oxidizers to the coal
prior to burning the coal in the boiler. This chemical addition
oxidizes the mercury present in the flue gas, which allows the plant to
remove mercury more readily from the flue gas in the wet FGD system.
EPA did not evaluate separate treatment technologies for the use of
oxidizers to control flue gas mercury emissions because using oxidizers
does not generate a separate FGMC wastewater.
To the extent that a power plant generates FGMC wastewater before
any BAT zero discharge limitation were to apply, the proposed BAT
limitations under Options 3a, 3b, 3, 4a, 4, and 5 would apply to
discharges of FGMC wastewater generated after the date established by
the permitting authority that is as soon as possible within the next
permit cycle after July 1, 2017. For indirect dischargers, EPA is
proposing that PSES for FGMC wastewater would apply to FGMC wastewater
generated after a date determined by the control authority that is as
soon as possible beginning July 1, 2017. As proposed today, legacy FGMC
wastewater generated by existing direct dischargers prior to that date
would remain subject to the existing BPT effluent limits; however, EPA
is also considering whether to set the BAT effluent limitations for
legacy FGMC wastewater equal to the existing BPT effluent limits. EPA
considered subjecting legacy FGMC wastewater to the proposed BAT/PSES
zero discharge requirements. As explained above, although most FGMC
wastes are managed using dry handling systems, EPA has identified six
plants that manage their FGMC waste with systems that use water to
transport the waste to surface impoundments. The technology basis
identified above for the proposed zero discharge requirement eliminates
the generation of the FGMC wastewater by implementing certain process
changes that do not use water to transport the FGMC waste; however, it
does not eliminate the already-generated FGMC wastewater that has
already been transferred to and stored in a surface impoundment. The
technologies that underlie regulatory Options 3a, 3b, 3, 4a, 4, and 5
do not represent BAT or PSES for the control of pollutants from legacy
FGMC wastewater and would not allow FGMC wastewater that has already
been generated to comply with a zero discharge requirement. As such,
EPA is not proposing BAT or PSES requirements associated with
discharges of legacy FGMC wastewater generated prior to the date
established by the permitting authority or control authority. However,
EPA is considering whether to set the BAT effluent limitations for
legacy FGMC wastewater equal to the existing BPT effluent limits. See
Section XVI for additional information.
Gasification Wastewater. The technology basis for the effluent
limitations for all eight regulatory options for gasification
wastewater is vapor-compression evaporation. Two operating IGCC plants
in the U.S. currently use this technology, and a third IGCC plant that
is scheduled to begin commercial operation soon will also use it to
treat gasification wastewater. Like leachate and FGMC wastewater,
gasification wastewater is currently included under the definition of
low volume wastes, with effluent limits for TSS and oil and grease
based on surface impoundments designed to remove suspended solids. EPA
considered using surface impoundments as the technology basis for one
or more of the regulatory options for gasification wastewater. However,
surface impoundments are not effective at removing the pollutants of
concern present in gasification wastewater. In addition, one of the
currently operating IGCC plants formerly used a surface impoundment to
treat its gasification wastewater and the impoundment effluent
repeatedly exceeded NPDES permit limits established to protect water
quality. Because of the demonstrated inability of surface impoundments
to remove the pollutants of concern and the current industry practice
of operating vapor-compression evaporation to treat the gasification
wastewater at all U.S. IGCC plants, EPA determined that surface
impoundments do not represent BAT level of control.
In addition to the vapor-compression evaporation technology that is
the basis for all BAT and BADCT/NSPS options for gasification
wastewater, EPA considered also including cyanide treatment as part of
the technology basis for one or more options. EPA notes that the
Edwardsport IGCC plant that is scheduled to soon begin commercial
operation includes cyanide destruction as one step in the treatment
process for gasification wastewater. However, EPA currently does not
have sufficient gasification wastewater data with which to calculate
effluent limits based on the performance of cyanide treatment as part
of a BAT/BADCT (NSPS) regulatory option. A possible approach to resolve
this would be to transfer effluent limits for cyanide from an ELG for
another industry sector. Alternatively, EPA may obtain effluent data
from the gasification wastewater treatment system for the Edwardsport
IGCC unit once it begins commercial operation and use these data to
calculate effluent limitations for cyanide. EPA solicits data on the
concentrations of cyanide present in gasification wastewater and
solicits comment on whether EPA should establish BAT or BADCT (NSPS)
control on the discharge of cyanide.
Nonchemical Metal Cleaning Wastes. The technology basis for the
effluent limitations for all eight regulatory options for nonchemical
metal cleaning wastes is chemical precipitation. Separation processes
in the physical/chemical treatment, along with chemical addition when
needed to facilitate coagulation and settling of suspended solids,
would effectively remove TSS and oil and grease to effluent
concentrations below the limitations included in the proposed rule. In
addition, treatment chemicals added to adjust pH to precipitate
dissolved metals or to facilitate flocculation/coagulation are
effective at removing copper and iron to effluent concentrations below
the proposed limitations, in addition to reducing the concentrations of
other pollutants present in nonchemical metal cleaning wastes.
The current ELG relies on three key terms specific to metal
cleaning waste: ``metal cleaning waste,'' ``chemical metal cleaning
waste,'' and ``nonchemical metal cleaning waste.'' The regulation
includes a definition of the broadest term, ``metal cleaning waste,''
as ``any wastewater resulting from cleaning [with or without chemical
cleaning compounds] any metal process equipment, including, but not
limited to, boiler tube cleaning, boiler fireside
[[Page 34465]]
cleaning, and air preheater cleaning.'' 40 CFR 423.11(d). Thus, this
definition includes any wastewater generated from either the chemical
or nonchemical cleaning of metal process equipment. In addition, the
regulation also defines ``chemical metal cleaning waste'' as ``any
wastewater resulting from cleaning of any metal process equipment with
chemical compounds, including, but not limited to, boiler tube
cleaning.'' See 40 CFR 423.11(c). The regulation also includes, but
does not expressly define the term ``nonchemical metal cleaning waste''
when it states that it has ``reserved'' the development of BAT ELGs for
such wastes. See 40 CFR 423.13(f). Although the regulation provides no
definition of ``nonchemical metal cleaning waste,'' it is clear from
the definitions of metal cleaning waste and chemical metal cleaning
waste that nonchemical metal cleaning waste is any wastewater resulting
from the cleaning of metal process equipment without chemical cleaning
compounds.
The current ELGs include BPT effluent limits for the allowable
levels of TSS, oil and grease, copper and iron in discharges of metal
cleaning waste, which includes both chemical and nonchemical metal
cleaning wastes. Although the current BPT effluent limits apply to
nonchemical metal cleaning wastes, EPA has found that some discharges
of nonchemical metal cleaning waste are authorized pursuant to permits
incorporating limitations based on BPT requirements for low volume
wastes and, therefore, do not have iron and copper limits. The
information EPA has collected to date indicates many facilities are not
discharging nonchemical metal cleaning wastewater or have copper and
iron limits (see Section VIII.A.3 and Section 7.7 of the TDD for more
information).
The current ELGs do not include BAT/NSPS requirements for the
broadly defined category of metal cleaning wastes; however, they do
include BAT/NSPS for chemical metal cleaning waste. EPA has not
promulgated BAT/NSPS for nonchemical metal cleaning waste. Similarly,
although the current ELGs do not include PSES/PSNS for metal cleaning
waste, they do include PSES/PSNS for chemical metal cleaning waste. EPA
has not promulgated PSES/PSNS for nonchemical metal cleaning waste. An
overview of the existing ELGs for metal cleaning waste, including
chemical and nonchemical metal cleaning waste, is provided below in
Table VIII-2.
Table VIII-2--Parameters Limited by Existing ELGs for Metal Cleaning Waste
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wastestream BPT BAT NSPS PSES PSNS
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Chemical Metal Cleaning Waste...... TSS, Oil & Grease, Copper, Iron.......... TSS, Oil & Grease, Copper............... Copper.
Copper, Iron. Copper, Iron.
Nonchemical Metal Cleaning Waste... ...................... Reserved.............. Reserved............. Reserved............. Reserved.
--------------------------------------------------------------------------------------------------------------------------------------------------------
As described above, EPA found that some discharges of nonchemical
metal cleaning waste are authorized pursuant to permits incorporating
limitations based on BPT requirements for low volume wastes and,
therefore, do not have iron and copper limits. Because the potential
costs for dischargers to comply with iron and copper limits is not
known, EPA is proposing to provide an exemption from new copper and
iron limitations or standards for existing discharges of nonchemical
metal cleaning wastes from generating units that are currently
authorized without iron and copper limits. For these discharges, BAT
limitations for nonchemical metal cleaning waste would be set equal to
BPT limitations for low volume waste, and the regulations would not
specify PSES. EPA solicits comment on the specific generating units
that should be included in the exemption. See Section VIII.A.3 for
additional details regarding the information that EPA is requesting as
part of the comment solicitation.
EPA is also considering setting BAT for nonchemical metal cleaning
waste equal to the metal cleaning waste BPT for all nonchemical metal
cleaning wastes (i.e., no exemption for discharges of nonchemical metal
cleaning wastes currently authorized without iron and copper limits)
and, for PSES, to establish copper standards for all discharges of
nonchemical cleaning wastes. As part of this approach, EPA is
evaluating whether some plants would incur costs to comply with the
current BPT standards. Therefore, as described later in this preamble,
EPA is also soliciting comments associated with each generating unit
with discharges of nonchemical metal cleaning wastes that are not
currently subject to the BPT copper and iron limits, in order to
understand the nonchemical metal cleaning wastes that are generated,
the characteristics of the wastewater, what actions would be needed to
comply with the proposed copper and iron limits, and estimated costs
associated with those actions. See Section VIII.A.3 for details
regarding the information that EPA is requesting as part of the comment
solicitation.
Anti-Circumvention Provisions. EPA is proposing to add provisions
to the regulations that would prevent facilities from circumventing the
effluent limitations guidelines and standards. The proposed provisions
would do three things, as described below.
First, the anti-circumvention provision would require that
compliance with the new effluent limits applicable to a particular
wastestream (e.g., FGD, gasification wastewater, leachate) be
demonstrated prior to use of the wastewater in another plant process
that results in surface water discharge or mixing the treated
wastestream with other wastestreams. Under 40 CFR 122.45(h), in
situations where an NPDES permit effluent limitations or standards
imposed at the point of discharge are impractical or infeasible,
effluent limitations or standards may be imposed on internal
wastestreams before mixing with other wastestreams or cooling water
streams. Limitations on internal wastestreams may be necessary, such as
in situations where the wastes at the point of discharge are so diluted
as to make monitoring impracticable, or the interferences among
pollutants would make detection or analysis impracticable. Many power
plants combine FGD wastewater and other power plant wastewaters with
ash transport water and/or cooling water prior to discharge, which can
dilute the wastewaters by several orders of magnitude prior to the
final outfall. In addition, surface impoundments typically contain a
variety of wastes (e.g., ash transport water, coal pile runoff,
landfill/impoundment leachate) that when mixed with the FGD wastewater
or gasification wastewater may make the analysis to measure compliance
with technology-based effluent limits impracticable. Because of the
high degree of dilution and the number of wastestream sources
containing similar pollutants, effluent
[[Page 34466]]
limits and monitoring requirements for certain internal wastestreams
(e.g., FGD wastewater, combustion residual leachate, gasification
wastewater) are necessary to ensure appropriate control of the
pollutants present in the wastewater. EPA requests comment on the
extent, if any, to which this provision may discourage water re-use.
Second, the anti-circumvention provision would establish
requirements intended to prevent steam electric power plants from
circumventing the effluent limits and standards by moving effluent
produced by a process operation for which there is a zero discharge
effluent limit/standard to another process operation for discharge
under less stringent requirements than intended by the steam electric
ELGs. For example, several options (including Option 3a) considered in
this rulemaking would establish a zero discharge requirement for
pollutants in fly ash transport water and FGMC wastewater. If this
option were selected for the final rule, the anti-circumvention
provisions would allow power plants to recycle/reuse these wastestreams
in ash transport processes or other plant processes, but only to the
extent that the plants do not discharge any pollutants associated with
flue gas mercury controls or transporting fly ash. The presence of a
zero discharge wastestream in a process that ultimately discharges to
surface water (e.g., use of fly ash transport water as FGD absorber
make-up water in a scrubber that discharges FGD wastewater) would not
be in compliance with the effluent limit. EPA requests comment on the
extent to which this provision may discourage water re-use.
Last, the anti-circumvention provisions would expressly require
permittees to use analytical EPA-approved methods that are sufficiently
sensitive to provide reliable quantified results at levels necessary to
demonstrate compliance with the effluent limits proposed by this
rulemaking when such methods are available. EPA's detailed study and
the field sampling for this rulemaking demonstrate that the use of
sufficiently sensitive analytical methods is critically important to
detecting, identifying, and measuring the concentrations of pollutants
present in power plant wastewaters. Where EPA has approved more than
one analytical method for a pollutant, the Agency expects that
permittees would select methods that are able to quantify the presence
of pollutants in a given discharge at concentrations that are low
enough to determine compliance with effluent limits, when such methods
are available. Facilities should not use a less sensitive or less
appropriate method, thus masking the presence of a pollutant in the
discharge, when an EPA-approved method is available that can quantify
the pollutant concentration at the lower levels needed for
demonstrating compliance. For purposes of the proposed anti-
circumvention provision, a method is ``sufficiently sensitive'' when
the sample-specific quantitation level \23\ for the wastewater being
analyzed is at or below the level of the effluent limitation. Allowing
plants to use insufficiently sensitive analytical methods for
compliance monitoring purposes when EPA-approved sufficiently sensitive
methods are available could result in an undetected exceedance of the
effluent limits.
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\23\ For the purposes of this rulemaking, EPA is considering the
following terms related to analytical method sensitivity to be
synonymous: ``quantitation limit,'' ``reporting limit,'' ``level of
quantitation,'' and ``minimum level.''
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BMPs for CCR Surface Impoundments. EPA is considering establishing
BMPs for plant operators to conduct periodic inspections of active and
inactive surface impoundments and to take corrective actions where
warranted. This requirement would apply to direct dischargers. For new
sources, EPA would be relying on CWA section 306, which authorizes the
promulgation of standards of performance for new sources. For existing
sources, EPA would be relying on CWA section 304(e), which authorizes
BMPs supplemental to ELGs for toxic or hazardous pollutants to control
plant site runoff, spillage or leaks, sludge or waste disposal, and
drainage from raw material storage which the Administrator determines
are associated with or ancillary to the industrial process and may
contribute significant amounts of pollutants to the nation's waters.
And CWA section 402(a) (2) authorizes the imposition of conditions,
which would include BMPs and monitoring requirements, necessary to
ensure compliance with all other applicable requirements. EPA's
regulation at 40 CFR 122.44(k) implements these authorities.
Specifically, 40 CFR 122.44(k) allow for NPDES permits to require the
use of BMPs to control and abate the discharge of toxic pollutants.
Existing regulations at 40 CFR 122.41(e) further require that NPDES
permittees properly operate and maintain all facilities and systems of
treatment and control used to achieve compliance with their permits.
This action provides notification that EPA is considering establishing
BMP requirements to address impoundment construction, operation, and
maintenance in the final ELG rule using CWA authority. Using CWA
authority, EPA could establish the BMPs as part of the ELGs (BAT and
NSPS) codified at 40 CFR part 423, and thus these BMPs would be
implemented through NPDES permits. Structural integrity requirements
that seek to reduce the potential for catastrophic releases from
surface impoundments could, alternatively, be established using RCRA
authority. The BMPs under consideration in this rulemaking are similar
to the structural integrity inspection and corrective active
requirements proposed in the CCR rulemaking, but do not include closure
requirements that were proposed as part of the CCR rulemaking.
The Agency believes that the BMP requirements being considered by
the Agency in this rulemaking and in the CCR rulemaking are critical to
ensure that the owners and operators of surface impoundments become
aware of any problems that may arise with the structural stability of
the surface impoundment before they occur and, thus, prevent
catastrophic releases, such as those that occurred at Martins Creek,
Pennsylvania and TVA's Kingston, Tennessee facility.
The BMPs being considered by EPA in this rulemaking would require,
first, that inspections be conducted every seven days by a person
qualified to recognize specific signs of structural instability and
other hazardous conditions by visual observation and, if applicable, to
monitor instrumentation such as piezometers. If a potentially hazardous
condition develops, the owner or operator shall immediately take action
to eliminate the potentially hazardous condition; notify the Regional
Administrator or the authorized State Director; and notify and prepare
to evacuate, if necessary, all personnel from the property that may be
affected by the potentially hazardous condition(s). Additionally, the
owner or operator must notify state and local emergency response
personnel if conditions warrant so that people living in the area down
gradient from the surface impoundment can evacuate. Reports of
inspections are to be maintained in the facility operating record.
Second, to address the integrity of surface impoundments, EPA would
establish BMPs for CCR surface impoundments similar to those
promulgated for coal slurry impoundments regulated by the Mine Safety
and Health Administration (MSHA) at 30 CFR 77.216. Although the
[[Page 34467]]
MSHA regulations are applicable to coal slurry impoundments at coal
mines and not to the impoundments containing CCR at power plants, there
are sufficient similarities between coal slurry and CCR impoundments
for the MSHA regulations to be used as a model for the BMP requirements
being considered for the ELG rule. Facilities using CCR impoundments
would need to (1) submit to EPA or the authorized state plans for the
design, construction, and maintenance of existing impoundments, (2)
submit to EPA or the authorized state plans for closure, (3) conduct
periodic inspections by trained personnel who are knowledgeable in
impoundment design and safety, and (4) provide an annual certification
by an independent registered professional engineer that all
construction, operation, and maintenance of impoundments is in
accordance with the approved plan. When problematic stability and
safety issues are identified, owners and operators would be required to
address these issues in a timely manner.
In developing these possible structural integrity BMP requirements,
EPA sought advice from the federal agencies charged with managing the
safety of dams in the United States. Many agencies in the federal
government are charged with dam safety, including the U.S. Department
of Agriculture (USDA), the Department of Defense (DOD), the Department
of Energy (DOE), the Nuclear Regulatory Commission (NRC), the
Department of Interior (DOI), and the Department of Labor (DOL), MSHA.
EPA looked particularly to MSHA, whose charge and jurisdiction appeared
to EPA to be the most similar to the Agency's in this context. MSHA's
jurisdiction extends to all dams used as part of an active mining
operation and their regulations cover ``water, sediment or slurry
impoundments'' so they include dams for waste disposal, freshwater
supply, water treatment, and sediment control. In fact, MSHA's current
impoundment regulations were created as a result of the dam failure at
Buffalo Creek, West Virginia on February 26, 1972. (This failure
released 138 million gallons of stormwater run-off and fine coal
refuse, and resulted in 125 persons killed, another 1,000 injured, over
500 homes completely destroyed, and nearly 1,000 others damaged.)
MSHA has nearly 40 years of experience writing regulations and
inspecting dams associated with coal mining. MSHA's regulations are
comprehensive and directly applicable to the dams used in surface
impoundments at coal-fired utilities to manage CCRs. EPA believes that,
based on the record compiled by MSHA for its rulemaking, and on MSHA's
40 years of experience implementing these regulations, the requirements
being considered in this rulemaking would substantially reduce the
potential for catastrophic release of CCRs from surface impoundments,
as occurred at TVA's facility in Kingston, Tennessee, and would
generally meet RCRA's objective to ensure the protection of humans and
the environment.\24\ Thus, EPA is considering establishing BMPs that
would be modeled on MSHA regulations in 30 CFR part 77.
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\24\ On December 22, 2008, the retention wall of a coal ash
impoundment at Tennessee Valley Authority's Kingston Plant
collapsed, which resulted in a massive release of CCRs directly into
the Emory River and its tributaries. The Emory River joins to the
Clinch River and then converges with the Tennessee River, a major
drinking water source for populations downstream. This failure
released over a billion gallons of fly ash and bottom ash, which
impacted over 100 properties, destroyed three homes, and ruptured a
gas line resulting in the evacuation of 22 residents.
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MSHA's regulations for coal slurry impoundments apply to those
impoundments at coal mines, which impound water, sediment or slurry to
an elevation of more than five feet and have a storage volume of 20
acre-feet or more and those coal slurry impoundments that impound
water, sediment, or slurry to an elevation of 20 feet or more. The BMPs
being considered today for the ELG rule would apply to all CCR
impoundments at steam electric power generating facilities, regardless
of height and storage volume. EPA is also considering variations on
BMPs for the ELGs, including, but not limited to, different inspection
frequencies or limitations on the applicability of BMPs that more
closely mirror the applicability of the MSHA regulations. EPA requests
comment on possible BMPs for inclusion in a final ELG rule including
those described above and any other appropriate variations on them.
Voluntary Incentive Program for Power Plants That Close CCR
Impoundments or Eliminate All Process Wastewater Discharges (Except
Cooling Water). EPA is considering establishing, as part of the BAT for
existing sources, a voluntary incentive program that provides more time
for plants to implement the proposed BAT requirements if they adopt
additional process changes and controls that provide significant
environmental protections beyond those achieved by the preferred
options for this proposed rule. The development of advanced process
changes and controls is a critical step toward the Clean Water Act's
ultimate goal of eliminating the discharge of pollutants into the
Nation's waters. See CWA Section 101(a)(1). Section 301(b)(1)(C)
demands that BAT result in ``reasonable further progress toward the
national goal of eliminating the discharge of pollutants.'' EPA intends
that, for any BAT option that is ultimately selected as part of any
final ELG rule, such option would represent ``reasonable further
progress,'' while the voluntary incentives program is designed to
continue progress toward achieving the national goal of the Act. In
addition, Section 104(a)(1) of the Act gives the Administrator
authority to establish national programs for the prevention, reduction,
and elimination of pollution, and it provides that such programs shall
promote the acceleration of research, experiments, and demonstrations
relating to the prevention, reduction, and elimination of pollution.
The voluntary incentives program being considered today would
effectively accelerate the research into and use of controls and
processes intended to prevent, reduce, and eliminate pollution because
it would increase the number of plants choosing to close and cap CCR
surface impoundments and eliminate discharges of all process wastewater
(except cooling water) to surface waters.
This voluntary program would establish two levels, or ``tiers,'' of
advanced technology performance requirements which would be
incorporated into the NPDES permits for the facilities that participate
in the program. Under Tier 1, power plants would be granted two
additional years (beyond the time described below in Section VIII.B) if
they also dewater, close and cap all CCR surface impoundments (except
for those impoundments containing only combustion residual leachate) at
the facility, including those surface impoundments located on non-
adjoining property that receive CCRs from the facility. A power plant
participating in the Tier 1 program could continue to operate surface
impoundments for which combustion residual leachate is the only type of
CCR solids or wastewater contained in the impoundment. In general,
power plants accepted in the Tier 1 incentives program would first
convert ash handling operations to dry handling or closed-loop tank-
based systems and FGD wastewater treatment operations to tank-based
systems, as described above in Section VI. This first step would
eliminate new contributions of CCRs (solids and wastewater) to the
surface impoundments. The plants would then dewater the impoundments by
draining
[[Page 34468]]
or pumping the wastewater from the impoundments, in compliance with the
ELGs and other requirements established in their NPDES permits. Upon
completing the dewatering operations, plants would then stabilize the
contents and close and cap the impoundments consistent with state
requirements and any other additional requirements that may be
established by EPA as part of the Tier 1 incentives program or other
applicable requirements.
Under Tier 2, power plants would be granted five additional years
(beyond the time described below in Section VIII.B) if they eliminate
the discharge of all process wastewater to surface waters, with the
exception of cooling water discharges. The Tier 2 incentives would not
be available to power plants that eliminate direct discharge to surface
water by sending the wastewater to a POTW. A plant accepted into the
Tier 2 incentives program would ultimately need to manage its processes
and wastewater in a manner that implements a coordinated approach
toward wastewater minimization, treatment and reuse. To achieve Tier 2
status, these plants would eliminate all process wastewater discharges
(except cooling water) by reducing the amount of wastewater generated
and preferentially using recycled wastewater to meet water supply
demands. To accomplish this, Tier 2 plants would conduct engineering
assessments of the processes that generate wastewater and identify
opportunities to eliminate or reduce the amount of wastewater they
generate. These plants would also assess the processes that use water
and determine how they could use recycled wastewater in those
processes, as well as the degree of treatment that may be needed to
enable such reuse. Based on responses to the industry survey, EPA has
identified a number of steam electric power plants that currently
discharge no process wastewater. In addition, two of the plants that
EPA visited in Italy previously discharged process wastewater, but have
implemented wastewater treatment and process changes, including
wastewater recycle, that now allow them to operate without discharging
any process wastewater except for their cooling water.
The primary objective of this program is to encourage individual
power plants to install advanced pollution prevention technologies or
make process changes that would further reduce releases of toxic
pollutants to the environment beyond the limits that would be set by
the proposed rule. The voluntary incentive program being considered is
designed to promote improvements that, in concert with other
environmental practices, make significant progress toward achieving
EPA's vision of the ``power plant of the future''--one which will have
a minimum impact on the environment. This program would give power
plants a platform to advance the research and development of
technologies and processes that promote water conservation and water
recycling and provide greater environmental protection. EPA has
conducted site visits at power plants that have implemented processes
that eliminate the use of water or recycle process wastewater to a
substantial degree. Furthermore, as noted above, EPA observed
operations at power plants that implemented process modifications and
treatment technologies that eliminated all discharges of process
wastewater with the exception of their cooling water. Implementing such
practices at other power plants would dramatically reduce discharges of
toxic and other pollutants. These practices would also substantially
reduce the amount of water consumed or used by the plant, which could
be an important consideration for addressing water availability and
other concerns. In exchange for providing additional time for power
plants to comply with the proposed BAT limitations, the program would
lead to superior effluent quality and greater environmental protection.
Participation in the program would be voluntary and it would be
available only to existing power plants that discharge directly to
surface waters. Power plants would have until July 1, 2017
(approximately 3 years after promulgation of the final ELGs) to commit
to the program and submit a plan for achieving the Tier 1 or Tier 2
requirements. Once a power plant enrolls in the program, the NPDES
permitting authority would develop specific discharge limits and key
milestones consistent with that tier.
Power plants enrolled in the program would ultimately be agreeing
to adopt NPDES permit limits that are more stringent than those that
would be required by the proposed and final BAT in exchange for
additional time to comply with their new effluent limitations. These
power plants and their corporate owners would also receive public
recognition for their commitment to increased environmental protection.
EPA considered including features of the Tier 1 and Tier 2
incentives as part of the options for the proposed rule. However,
although EPA has observed these practices in operation and they are
available for at least a portion of the industry, the degree of
complexity will vary from plant to plant and EPA does not have the
site-specific information that could be used to sufficiently assess how
that complexity may affect the engineering challenges and costs that
plants would encounter. EPA requests comment on the voluntary
incentives program described in this section and any appropriate
variations.
3. Rationale for the Proposed Best Available Technology (BAT)
BAT represents the best available economically achievable
performance of facilities in an industrial subcategory or category
taking into account factors specified in the CWA. The CWA factors
considered in assessing BAT are the cost of achieving BAT effluent
reductions, the age of equipment and facilities involved, the process
employed, potential process changes, and non-water quality
environmental impacts, including energy requirements and such other
factors as the Administrator deems appropriate. See Section
304(b)(2)(B). In addition to technological availability, economic
achievability is also a factor considered in setting BAT. See Section
301(b)(2)(A).
After considering all of the technologies described in Section
VII.B.2, in light of the factors specified in Section 304(b)(2)(B) and
Section 301(b)(2)(A) of the CWA, as appropriate, EPA is putting forth
four preferred alternatives for BAT. These four preferred alternatives
primarily differ in that some would establish more environmentally
protective BAT requirements for discharges from two of the wastestreams
from existing sources. Under the first preferred alternative, EPA is
proposing to establish BAT effluent limits based on the technologies
specified in Option 3a. With the exception of oil-fired generating
units and small generating units (i.e., 50 MW or smaller), the proposed
rule under Option 3a would:
Establish a ``zero discharge'' effluent limit for all
pollutants in fly ash transport water and FGMC wastewater;
Establish numeric effluent limits for mercury, arsenic,
selenium, and TDS in discharges of gasification wastewater;
Establish numeric effluent limits for copper and iron in
discharges of nonchemical metal cleaning wastes \25\;
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\25\ As described later in this section, EPA is proposing to
exempt from new BAT copper and iron limitations existing discharges
of nonchemical metal cleaning wastes that are currently authorized
under their existing NPDES permit without iron and copper limits.
For these discharges, BAT limits would be set equal to BPT limits
for low volume waste.
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Establish BAT effluent limits for bottom ash transport
water and
[[Page 34469]]
combustion residual leachate that are equal to the current BPT effluent
limits for these discharges (i.e., numeric effluent limits for TSS and
oil and grease; and
BAT for discharges of FGD wastewater would continue to be
determined on a site-specific basis.
Under the second preferred alternative for BAT, EPA is proposing to
establish BAT effluent limits based on the technologies specified in
Option 3b. With the exception of oil-fired generating units and small
generating units (i.e., 50 MW or smaller), the proposed rule under
Option 3b would:
Establish numeric effluent limits for mercury, arsenic,
selenium, and nitrate-nitrite in discharges of FGD wastewater for units
located at plants with a total wet-scrubbed capacity of 2,000 MW or
more 26 27;
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\26\ Total plant-level wet-scrubbed capacity is calculated by
summing the nameplate capacity for all of the units that are
serviced by wet FGD systems.
\27\ For units below the 2,000 MW threshold, BAT would continue
to be determined on a site-specific basis.
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Establish a ``zero discharge'' effluent limit for all
pollutants in fly ash transport water and FGMC wastewater;
Establish numeric effluent limits for mercury, arsenic,
selenium, and TDS in discharges of gasification wastewater;
Establish numeric effluent limits for copper and iron in
discharges of nonchemical metal cleaning wastes \28\; and
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\28\ As described later in this section, EPA is proposing to
exempt from new BAT copper and iron limitations existing discharges
of nonchemical metal cleaning wastes that are currently authorized
under their existing NPDES permit without iron and copper limits.
For these discharges, BAT limits would be set equal to BPT limits
for low volume wastes.
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Establish BAT effluent limits for bottom ash transport
water and leachate that are equal to the current BPT effluent limits
for these discharges (i.e., numeric effluent limits for TSS and oil and
grease).
Under the third preferred alternative for BAT, EPA is proposing to
establish BAT effluent limits based on the technologies specified in
Option 3. In addition to the requirements described for Option 3b, the
proposed rule would establish the same numeric effluent limits as in
Option 3b for mercury, arsenic, selenium, and nitrate-nitrite in
discharges of FGD wastewater from units located at all steam electric
facilities, with the exception of oil-fired generating units and small
generating units (i.e., 50 MW or less).
Under the fourth preferred alternative for BAT (Option 4a), in
addition to the requirements described for Option 3, the proposed rule
would establish ``zero discharge'' effluent limits for all pollutants
in bottom ash transport water from units greater than 400 MW.
For oil-fired generating units and small generating units (i.e., 50
MW and smaller) that are existing sources, under all four preferred
options, EPA is proposing to set the BAT effluent limits equal to the
current BPT effluent limits for copper and iron for nonchemical metal
cleaning wastes,\29\ and for TSS and oil and grease for five of the six
wastestreams listed above (i.e., FGD wastewater, fly ash transport
water, FGMC wastewater, leachate from landfills and surface
impoundments containing combustion residuals, and gasification
wastewater). EPA is proposing Options 3a, 3b, 3 and 4a as the preferred
BAT regulatory options because its analysis to this date suggests that
they are all technologically available, economically achievable, and
have acceptable non-water quality environmental impacts. However, EPA
is putting forth a range of options as candidates for BAT in order to
enhance the Agency's understanding of the pros and cons of each of
these options in light of the statutory factors through the public
comment process and intends to evaluate this information and how it
relates to the factors specified in the CWA. As discussed above in
Sections VI and VIII.A.2, the data in EPA's record and its analysis to
date suggests that all four options are technologically available.
EPA's record indicates that the technologies comprising Options 3a, 3b,
3, and 4a are well-demonstrated and have been employed at a subset of
existing power plants.
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\29\ As described later in this section, EPA is proposing to
exempt from new BAT copper and iron limitations existing discharges
of nonchemical metal cleaning wastes that are currently authorized
under their existing NPDES permit without iron and copper limits.
For these discharges, BAT limits would be set equal to BPT limits
for low volume waste.
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Under all of the preferred options, the technology basis for fly
ash transport water is dry handling. All generating units built in the
30 years since the ELGs were last revised in 1982 have been subject to
a zero discharge standard for the pollutants in fly ash transport
water, in nearly all cases installing dry fly ash handling technologies
to comply with the standard. In addition, many other generating units
that could discharge their fly ash transport water upon meeting a TSS
effluent limit have instead retrofitted the dry fly ash handling
technology to meet operational needs or for economic reasons.
Approximately 40 percent of the plants that were operating wet-sluicing
systems in 2000 have converted generating units to dry fly ash
(approximately 115 generating units at 45 power plants). Another 61
generating units are slated to convert to dry fly ash handling by 2020.
Based on data collected by the industry survey, approximately 66
percent of coal- and petroleum coke-fired generating units handle all
fly ash with dry technologies. Another 15 percent of coal- and
petroleum coke-fired generating units have both wet and dry fly ash
handling systems (typically, the wet system is a legacy system that the
plant has not decommissioned following retrofit with a dry system).
Only 19 percent of coal- and petroleum coke-fired generating units
exclusively use a wet fly ash handling system. Furthermore, some of
these plants with wet fly ash handling systems manage the ash handling
process so that they do not discharge fly ash transport water. As a
result, EPA determined that only 13 percent of coal-fired power plants
would incur costs to comply with a BAT zero discharge requirement for
fly ash transport water. See Section 9.7.3 of the TDD.
Power plants recently began installing FGMC systems either to
comply with state requirements or to prepare for emissions limits
established by the MATS rule. Plants using sorbent injection systems
(e.g., activated carbon injection) typically handle the spent sorbent
in the same manner as their fly ash. Nearly all plants with FGMC
systems use dry handling technologies. Only a few plants use wet
systems to transport the spent sorbent to disposal in surface
impoundments. Based on the industry survey, the plants using wet
handling systems currently operate them as closed-loop systems and do
not discharge FGMC wastewater to surface waters, or have the capability
to do so. These plants could continue to operate these wet systems as
closed-loop systems, or could convert to dry handling technologies by
managing the fly ash and spent sorbent together in a retrofitted dry
system (the wastes are currently managed together in the impoundments)
or by installing dedicated dry handling equipment for the FGMC wastes
similar to the equipment used for fly ash.
The technology basis for control of discharges of FGD wastewater
under Options 3, 3b (for units located at plants with a total wet-
scrubbed capacity of 2,000 MW or more), and 4a is chemical
precipitation followed by anaerobic biological treatment. Four power
plants, or approximately three percent of wet-scrubbed power plants
that discharge FGD wastewater already have the
[[Page 34470]]
Options 3b (for units located at plants with a total wet-scrubbed
capacity of 2,000 MW or more), 3 and 4a BAT technology in place. Under
Options 3b (for units located at plants with a total wet-scrubbed
capacity of 2,000 MW or more), 3, and 4a, in addition to other new
requirements that would be established, numeric limits would be
established for toxic discharges including arsenic, mercury, and
selenium from FGD wastewater.
The technology used as the basis for FGD wastewater treatment under
Options 3b (for units at plants with a total wet-scrubbed capacity of
2,000 MW or more), 3 and 4a has been tested at power plants for more
than 10 years and full-scale systems have been operating at a subset of
plants for 5 years. The biological treatment processes used in the
bioreactor portion of the treatment technology have been widely used in
many industrial applications for decades both in the U.S. and
internationally. Five steam electric power plants operate fixed-film
anoxic/anaerobic biological treatment systems to treat FGD wastewater
and another operates a suspended growth biological treatment system
that targets removal of selenium.\30\ Other power plants are
considering installing the biological treatment technology to remove
selenium and at least one plant is moving forward with construction.
See DCN SE03874. In addition, four additional power plants currently
operate anaerobic biological treatment systems for their FGD
wastewater, indicative that this is available technology. EPA is aware
of industry concerns with the feasibility of biological treatment at
some power plants. Specifically, industry has asserted that the
efficacy of these systems is unpredictable, and is subject to
temperature changes, high chloride concentrations, and high oxidation
reduction potential in the absorber (which may kill the treatment
bacteria). EPA's record to date does not support these assertions, but
is interested in additional information that addresses these concerns.
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\30\ Four of the six operate the biological treatment systems in
combination with chemical precipitation.
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More than one-third of plants that discharge FGD wastewater utilize
chemical precipitation (in some cases, also using additional treatment
steps). As noted above, four power plants currently operate chemical
precipitation systems in combination with anaerobic biological
treatment systems. The chemical precipitation treatment processes
included in the FGD wastewater technology basis for these options are
used at 24 percent of steam electric power plants that discharge FGD
wastewater (and another 11 percent of plants also use chemical
precipitation systems that could be upgraded to this technology basis)
and also at thousands of industrial facilities nationwide (See Section
8.1.3 of the TDD).\31\
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\31\ Physical/chemical treatment systems can be effective at
removing mercury and certain other metals; however, to achieve
effective removal of selenium this technology must be coupled with
additional treatment technology such as anoxic/anaerobic biological
treatment.
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Option 3b proposes limitations based on this technology for units
at the largest plants (as determined by a 2,000 MW total wet-scrubbed
capacity threshold), and BAT for the control of discharges of FGD
wastewater from units at plants below this threshold would continue to
be determined on a site-specific basis. For FGD wastewater only, EPA
believes any threshold should be based on a plant level rather than a
unit level because many plants currently use a single FGD treatment
systems to service multiple units. Additionally, EPA determined that
wet-scrubbed capacity is an appropriate metric because it only reflects
units that are generating FGD wastewater. For example, a plant could
have a total plant nameplate generating capacity of 3,500 MW, but only
have a wet-scrubbed capacity of 200 MW if only one of its units is wet-
scrubbed. EPA is putting forth this option as a preferred option based
on an assumption that these facilities are more able to achieve these
limits based on economies of scale. These largest facilities will
likely also be able to absorb the costs of installing and operating the
chemical precipitation and anaerobic biological treatment systems on
which the FGD wastewater limitations are based. For these reasons, as
well as those specified above related to current innovation and
treatment trends, Option 3b proposes that BAT effluent limitations for
discharges of FGD wastewater would continue to be determined on a site-
specific basis for units at facilities below the 2,000 MW threshold.
EPA solicits comment on the proposed 2,000 MW threshold applicable to
discharges of FGD wastewater under Option 3b, including whether this or
another threshold may be more appropriate.
The fourth preferred alternative for this proposed rule, Option 4a,
in addition to the requirements that would be established under Option
3, would eliminate discharges of pollutants in bottom ash transport
water from units greater than 400 MW. The technology basis for bottom
ash for the zero discharge requirement is dry handling or a closed-loop
system. Bottom ash transport water is one of the three largest sources
for discharges of the pollutants of concern from steam electric power
plants and these discharges occur at many power plants across the
nation. Based on data collected by the industry survey, approximately
30 percent of coal-fired and petroleum coke-fired power plants handle
bottom ash using technologies that do not generate any transport water.
In addition, another 12 percent of coal- and petroleum coke-fired power
plants manage the wet-sluicing bottom ash handling system as a closed-
loop system that recirculates all bottom ash transport water so that it
is not discharged. In addition, 83 percent of coal-fired generating
units built in the last 20 years installed dry bottom ash handling
systems.
EPA recognizes that the potential costs associated with compliance
with a zero discharge standard for discharges of bottom ash transport
water would be substantial if applied to all facilities (for example,
approximately half of Option 4 costs and approximately a third of
Option 5 costs), and, therefore, looked carefully at this wastestream
with a particular focus on generating unit size. Our review
demonstrated that, in the case of bottom ash transport water, units
less than or equal to 400 MW are more likely to incur compliance costs
that are disproportionately higher per MW than those incurred by larger
units. For example, the average annualized cost of achieving zero
discharge limits for bottom ash discharges (i.e. dry handling or closed
loop) per MW for a 200 MW unit is more than three times higher than the
average cost for a 400 MW unit. Based on the data from the industry
survey, EPA estimates that 25 percent of coal-fired power plants would
incur costs to comply with a BAT zero discharge requirement for bottom
ash transport water from units greater than 400 MW.
Furthermore, while all plants, regardless of size, are capable of
installing and operating dry handling or closed-loop systems for bottom
ash transport water, and the costs would be affordable for most plants,
EPA believes that companies may choose to shut down 400 MW and smaller
units instead of making new investments to comply with proposed zero
discharge bottom ash requirements. EPA is basing this belief on its
review of units that facilities have announced will be retired or
converted to non-coal based fuel sources. Of those units that plants
have announced for retirement, and that also
[[Page 34471]]
generate bottom ash transport water, over 90 percent are 400 MW or
less. See DCN SE03834.
Therefore, for the reasons specified above, for units less than or
equal to 400 MW, Option 4a proposes to set the BAT effluent limits
equal to the current BPT effluent limits based on surface impoundments.
EPA solicits comment on the proposed 400 MW threshold applicable to
discharges of bottom ash transport water under Option 4a, including
whether this or another threshold may be more appropriate.
The two IGCC plants currently operating in the United States use
the technology that is the basis for all four preferred options for
gasification wastewater. A third IGCC plant that will soon begin
commercial operation will also use the technology and, in addition to
that, will also operate a cyanide destruction step as part of the
treatment system.
For all four preferred options, the proposed BAT limits for copper
and iron in discharges of nonchemical metal cleaning waste are equal to
the current BPT effluent limits for these pollutants in metal cleaning
waste. These effluent limits are based on the same technology that was
used as the basis for the current ELG BPT requirements for metal
cleaning waste (i.e., chemical precipitation).
Discharges of metal cleaning wastes that are generated from
cleaning metal process equipment without chemical cleaning compounds
(i.e., nonchemical metal cleaning waste) are already subject to BPT
effluent limits for copper and iron equal to the BAT effluent limits
being proposed today. Based on responses to the industry survey,
facilities typically treat both chemical and nonchemical metal cleaning
waste in similar fashion.
Since, as described above, nonchemical metal cleaning waste is
included within the definition of metal cleaning waste, and copper and
iron are already regulated under metal cleaning wastes, EPA would be
establishing BAT limits equal to the BPT limits (for copper and iron)
that already apply to these wastes. As a result, facilities should
incur no cost to comply with the proposed BAT for these wastes.
However, EPA recognizes that previous guidance provided after the final
1974 regulation stated that wastes from metal cleaning with water are
considered ``low volume'' wastes. The extent to which this statement
was relied upon is unclear, and EPA rejected the guidance in the 1982
rulemaking for the steam electric ELGs (47 FR 52297). However, because
permitting authorities and others may have relied on this guidance and
the potential costs to those facilities are not known, EPA is proposing
to exempt from any new copper and iron BAT requirements those
discharges of nonchemical metal cleaning waste to which this guidance
was applied in the past. In other words, EPA is proposing to exempt
from proposed new copper and iron BAT limitations those discharges of
nonchemical metal cleaning wastes from generating units that are
currently authorized to discharge nonchemical metal cleaning wastes
without copper and iron limits pursuant to existing BPT requirements
for metal cleaning waste. For such discharges, EPA is proposing to set
BAT limitations equal to BPT limitations for low volume waste.
To get a better understanding of how discharges of nonchemical
metal cleaning wastes are currently permitted, EPA's regional offices
recently reviewed 45 permits for plants that EPA had reason to believe
generated nonchemical metal cleaning waste based on responses to the
industry survey. For these permits, EPA determined the following based
on the review:
64 percent of the plants are either zero discharge of
metal cleaning wastes or have to comply with copper and iron limits;
27 percent of plants do not have to comply with copper and
iron limits; and
9 percent of plant permits do not include enough
information to determine whether the plant would be in compliance with
the proposed BAT limitations.
While not exhaustive, this review provides some information to suggest
that many, but not all, plants are either zero discharge or have iron
and copper limits and thus are already meeting these proposed BAT
limitations. Also see Section 7.7 of the TDD.
In order to implement the exemption proposed today for certain
discharges of nonchemical metal cleaning waste that have historically
been treated as low volume wastes and not subject to copper and iron
limits under metal cleaning waste BPT requirements, EPA's current
thinking is to develop a specific list of generating units eligible for
the exemption. Therefore, EPA is seeking to identify those generating
units that should be eligible for the exemption through the public
comment process on this rulemaking. To qualify for the proposed
exemption, the generating unit must meet all three of the following
criteria:
The generating unit must currently generate nonchemical
metal cleaning wastes;
The generating unit must discharge the nonchemical metal
cleaning waste; and
The generating unit must be located at a plant that is
authorized to discharge the nonchemical metal cleaning waste without
limitations for copper and iron.
If the nonchemical metal cleaning wastes generated and discharged by a
generating unit do not meet all of these three criteria, then EPA
proposes that the generating unit will not be eligible for the
exemption. For example, if the plant currently hauls the nonchemical
metal cleaning wastes off site for disposal, the generating units
associated with the nonchemical metal cleaning waste generation would
not be exempt. Any public comments submitted with the intention of
identifying generating units that might appropriately fall within the
exemption must provide the necessary documentation (e.g., permits, fact
sheets) to support a finding that the generating unit meets all three
criteria. EPA also requests comment on this general method of
implementing the exemption. Another approach would be to define the
conditions of the exemption, and then make it available to any facility
that qualified, regardless of whether the facility was identified to
EPA during the comment period. This would give EPA less information on
the potential effects of including this exemption in the final rule,
but would also allow qualified facilities to make use of the exemption
even if they were unaware of the need to file comments during the
comment period in order to make use of it. EPA requests comment on
this, or any other, way of implementing the proposed exemption.
EPA is also considering setting BAT limitations equal to BPT
limitations applicable to metal cleaning waste for all discharges of
nonchemical metal cleaning wastes (i.e., not creating an exemption from
copper and iron limits for discharges of nonchemical metal cleaning
wastes from generating units currently authorized to discharge those
wastes without copper and iron limits). As part of this approach, EPA
is evaluating whether plants would incur costs to comply with the
current BPT requirements applicable to discharge of metal cleaning
wastes. Therefore, EPA is also soliciting comments that provide
information on those generating units that are not currently subject to
the BPT metal cleaning waste limitations for copper and iron, in order
to understand what actions would be required to comply with the
proposed BAT nonchemical metal cleaning waste limitations for iron and
copper. EPA is
[[Page 34472]]
particularly interested in the following information:
Type of nonchemical metal cleaning waste generated,
frequency of generation, and volume generated;
Wastewater characterization data (i.e., monitoring data)
for the nonchemical metal cleaning waste; \32\
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\32\ Commenters should provide available monitoring data (i.e.,
EPA is not requiring the commenters to collect additional samples).
Additionally, commenters should specify what data are represented by
the characterization data (which wastestreams were sampled, the
percent contribution of each wastestream, whether the samples are
untreated or treated, and if treated, the type of treatment system
represented).
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Information regarding the actions that would need to be
taken to comply with the iron and copper limits for the nonchemical
metal cleaning wastes discharged; and
Estimated capital and operating and maintenance costs,
broken out by specific cost components (e.g., equipment costs,
installation costs, labor costs), to comply with the proposed copper
and iron limits, along with the basis for the cost estimate.
EPA's analysis to date suggests that all four preferred options,
Option 3a, Option 3b, Option 3, and Option 4a, are economically
achievable. EPA performed cost and economic impact assessments using
the Integrated Planning Model (IPM) for Option 3 and Option 4.\33\
Option 4 is more costly than any of the four preferred options
including Option 4a; therefore by performing the assessments with these
two options, EPA can evaluate the potential effects of each of the
preferred options. Because the costs and the facilities affected by
Option 3a and 3b are a subset of Option 3, EPA can use the results of
Option 3 to inform the potential impacts of Option 3a and Option 3b. In
a similar way, because the costs and the facilities affected by Option
4a are a subset of Option 4, EPA can use the results of Option 4 to
inform the potential impacts of Option 4a.
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\33\ IPM is a comprehensive electricity market optimization
model that can evaluate such impacts within the context of regional
and national electricity markets. See Section XI for additional
discussion.
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For the options analyzed overall, the model showed very small
effects on the electricity market, on both a national and regional sub-
market basis. Based on the results of these analyses, EPA estimates
that the proposed requirements associated with Option 3a, Option 3b,
and Option 3 would not lead to the premature retirement of any steam
electric generating units (i.e., no partial or full plant closures).
The results for Option 4 show fourteen unit (partial) closures and
zero plant (full) closures projected as of the model year 2030,
reflecting full compliance of all facilities.34 35 The 14
generating units are located at six plants. The IPM results also show
that five steam electric units that are projected to close under the
base case (i.e., in the absence of the proposed revisions to the ELG)
would remain operating under proposed Option 4 (i.e., avoiding
closure). As a result, for Option 4, the IPM analysis projects total
net closure of nine generating units, with total combined generating
capacity of 317 MW. These results support EPA's conclusion that Option
4 is economically achievable. As explained above, because the costs and
facilities affected by Option 4a are only a subset of Option 4 (i.e.,
are less than those for Option 4), the model would project similar or
smaller effects for Option 4a. These IPM estimates for closures and
avoided closures also support EPA's conclusion that Option 4a is
economically achievable for the steam electric industry.
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\34\ As used here for the purpose of this rulemaking, the term
partial closure refers to a plant where the closure of a generating
unit is projected, but one or more generating units at the plant
will continue operating. A full closure refers to a situation where
all generating units at a plant are projected to shut down.
\35\ Given the design of IPM, unit-level and thereby plant-level
projections are presented as an indicator of overall regulatory
impact rather than a prediction of future unit-level or plant-
specific compliance actions.
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As part of its consideration of technological availability and
economic achievability, EPA also considered the magnitude and
complexity of process changes and new equipment installations that
would be required at facilities to meet the requirements of the rule.
As described in greater detail in Section XVI, EPA is proposing that,
where the limitations and standards being proposed today for existing
direct and indirect dischargers are more stringent than existing BPT
requirements, those limitations and standards do not begin to apply
until July 1, 2017 (approximately three years following promulgation of
the final rule). EPA is proposing this approach to provide the time
that many facilities will need to raise capital, plan and design
systems, procure equipment, and construct and then test systems.
Moreover, this approach will enable facilities to take advantage of
planned shutdown or maintenance periods to install new pollution
control technologies. EPA's proposal is designed to minimize any
potential impacts on electricity availability caused by forced outages.
Options 3a, 3b, 3 and 4a have acceptable non-water quality
environmental impacts, as discussed in Section XV of the preamble and
in the TDD. EPA estimates that Options 3a, 3b, 3, and 4a would increase
energy consumption by less than 0.003 percent, less than 0.004 percent,
less than 0.008 percent, and less than 0.012 percent, respectively, of
the total electricity generated by power plants. EPA also estimates
that Options 3a, 3b, 3, and 4a would increase the amount of fuel
consumed by increased operation of motor vehicles (e.g., for
transporting fly ash) by less than 0.009 percent, less than 0.009
percent, less than 0.009 percent, and less than 0.014 percent,
respectively, of total fuel consumption by all motor vehicles.
As discussed in Section XV.B., EPA also evaluated the effect of the
proposed rule on air emissions generated by power plants
(NOX, sulfur oxides (SOX), and CO2).
For Options 3a, 3b, and 3, the NOX emissions are estimated
to increase by no more than 0.12 percent, and for Option 4a, by no more
than 0.13 percent. EPA projects no significant increase in emissions of
SOX or CO2 under the four preferred options.
EPA also evaluated the effect of the proposed rule on solid waste
generation and water usage. There would be no increase in solid waste
generation under Option 3a, and EPA estimates that solid waste
generation at power plants will increase by less than 0.001 percent
under the other three preferred options. EPA estimates the power plants
would reduce water use by 50 billion gallons per year (136 million
gallons per day) under Option 3a, 52 billion gallons per year (143
million gallons per day) under Option 3b, 53 billion gallons per year
(144 million gallons per day) under Option 3, and 103 billion gallons
per year (282 million gallons per day) under Option 4a.
EPA also examined the effects of the preferred options on consumers
as an ``other factor'' that might be appropriate when considering what
level of control represents BAT. If all compliance costs were passed on
to residential consumers of electricity instead of being borne by the
operators and owners of power plants, the monthly increase in
electricity bill would be no more than $0.04, $0.06, $0.13, and $0.22,
respectively under Options 3a, 3b, 3, and 4a.
EPA is not proposing either Option 1 or Option 2 as its preferred
option for BAT because neither option would represent the best
available technology level of control for steam electric power plant
discharges. For example, Options 1 and 2 would allow plants to continue
[[Page 34473]]
to discharge fly ash transport wastewater without treating the wastes
to remove dissolved metals and many of the other pollutants present in
the wastewater. However, 66 percent of all coal- and petroleum coke-
fired generating units that produce fly ash as a residue of the
combustion process already use dry fly ash technologies to manage all
of their fly ash without any associated creation or discharge of fly
ash transport water. And another 15 percent of the coal- and petroleum
coke-fired generating units that produce fly ash also already operate
dry fly ash handling systems in addition to a wet ash handling system
(either as a completely redundant system, or to manage a fraction of
the fly ash that is produced during combustion). Similarly, every
generating unit operating a FGMC system does so in a manner that avoids
creating any FGMC wastewater (92 percent of units with FGMC), or
manages the FGMC wastewater in a closed cycle process that does not
result in a discharge to surface water (8 percent of units with FGMC).
The technology serving as the basis for FGD effluent limits under
Option 1 is not effective at removing many of the pollutants of concern
in FGD wastewater, including selenium, nitrogen compounds, and certain
metals that contribute to high concentrations of total dissolved solids
in FGD wastewater (e.g., bromides, boron). Furthermore, the information
in the record for this proposed rule demonstrates that the amount of
mercury, selenium, and other pollutants removed by the biological
treatment stage of the treatment system, above and beyond the amount of
pollutants removed in the chemical precipitation treatment stage
preceding the bioreactor, can be substantial. Options 1 and 2 would
remove fewer or similar levels of pollutants to the preferred options,
all of which EPA believes, based on its analysis to date, to be
technologically available, economically achievable, and have acceptable
non-water quality environmental impacts. Options 1 and 2 would
establish new effluent limits for three of the seven key wastestreams
addressed in this rulemaking. For the remaining four wastestreams, BAT
effluent limits would be set equal to the current BPT effluent limits.
EPA did not select Option 4 as its preferred regulatory option
because of concerns expressed above associated with the projected
compliance costs associated with zero discharge requirements for bottom
ash for units equal to or below 400 MW. The bottom ash requirements for
Option 4 and the preferred Option 4a are the same with the exception
that Option 4a proposes to set the BAT effluent limits for bottom ash
transport water equal to the current BPT effluent limits for units less
than or equal to 400 MW, while Option 4 would set the BAT effluent
limits for bottom ash transport water equal to the BPT effluent limits
for units less than or equal to 50 MW. All other units would be subject
to ``zero discharge'' effluent limits for all pollutants in bottom ash
transport water.
Moreover, Option 4 proposes to establish BAT discharge limitations
for toxic discharges for leachate. The record demonstrates that the
amount of pollutants collectively discharged in leachate by steam
electric plants is a very small portion of the pollutants discharged
collectively for all steam electric power plants (i.e., less than \1/2\
a percent). The technology basis for limitations on discharges of
combustion residual leachate proposed under Option 4 is chemical
precipitation. Because of the relatively low level of pollutants in
this wastestream, and because EPA believes this is an area ripe for
innovation and improved cost effectiveness, EPA is not putting forward
this option as a preferred option. On balance, EPA would like to
collect additional information on costs and effectiveness of chemical
precipitation and other possible technologies for reducing pollutants
discharged in leachate before making a finding with respect to what
technologies represent the best available technology economically
achievable for controlling discharges of pollutants found in combustion
residual leachate. Consequently, EPA is interested in receiving
information through the public-comment process related to cost,
pollutant reduction, and effectiveness data on chemical precipitation
and alternative approaches to treatment of combustion residual
leachate.
EPA did not select Option 5 as its preferred option for BAT because
of the high total industry cost for the option ($2.3 billion/year
annualized social cost) and because of preliminary indications that
Option 5 may not be economically achievable. While EPA has
traditionally looked at affordability of the rule to the regulated
industry, EPA has in some limited instances over the past three decades
rejected an option primarily on the basis of total industry costs. See
48 FR 32462, 32468 (July 15, 1983) (Final Rule establishing ELGs for
the Electroplating and Metal Finishing Point Source Categories); 74 FR
62996, 63026 (Dec. 1, 2009) (Final Rule establishing ELGs for the
Construction and Development Point Source Category); BP Exploration &
Oil, Inc. v. EPA, 66 F.3d 784, 796-97 (6th Cir. 1996) (upholding EPA's
decision not to require zero discharge of produced waters based on
reinjection for the Offshore subcategory of the Oil and Gas Extraction
Point Source Category based in part on total industry cost). EPA
similarly finds this appropriate here. In addition, certain screening-
level economic impact analyses indicated that compliance costs may
result in financial stress to some entities owning steam electric
plants. Although EPA did not select Option 5 as the preferred BAT
option, without question, Option 5 would remove the most pollutants
from steam electric power plant discharges. Also, the technologies are
all potentially available and may be appropriate (individually or in
totality) as the basis for water quality-based effluent limits in NPDES
permits, depending on site-specific conditions. For example, any of the
requirements that would be established under Option 5, including at a
minimum the vapor compression evaporation technology serving as the
Option 5 technology basis for FGD wastewater, may be appropriate for
those power plants that discharge upstream of drinking water treatment
plants and that have bromide releases in wastewaters that impact
treatment of source waters at the drinking water treatment plants.
Section XIII of the preamble includes additional discussion about
discharges of bromides. Also, see the EA.
For the reasons described below in Section VIII.B., EPA is
proposing that, where the limitations and standards being proposed
today are more stringent than existing BPT requirements, those
limitations and standards do not begin to apply until July 1, 2017
(approximately three years from the effective date of this rule).
For all eight of the main BAT options under consideration, EPA is
proposing to establish effluent limits for oil-fired generating units
and small generating units (i.e., 50 MW or less) that differ from the
effluent limits for all other generating units.\36\ For oil-fired
generating units and small generating units, EPA is proposing to set
the BAT effluent limits equal to the current BPT effluent limits for
all seven of the key wastestreams addressed by this proposed rule. For
six of these wastestreams, BAT would be set equal to current BPT
numeric limits for TSS
[[Page 34474]]
and oil and grease, with these pollutants regulated as indicator
pollutants for the control of toxic and nonconventional pollutants. For
nonchemical metal cleaning wastes, EPA is proposing to set BAT equal to
the current BPT effluent limits for copper and iron in metal cleaning
wastes \37\, but would not establish BAT effluent limits for TSS and
oil and grease (which are also currently regulated by BPT for metal
cleaning wastes). EPA's proposal and reasoning is detailed below.
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\36\ For Option 4a, for discharges of pollutants found in bottom
ash transport water only, as explained previously, EPA is proposing
to raise the value from less than or equal to 50 MW to less than or
equal to 400 MW.
\37\ As described earlier in this section, EPA is proposing to
exempt from new BAT copper and iron limitations existing discharges
of nonchemical metal cleaning wastes that are currently authorized
under their existing NPDES permit without iron and copper limits.
For these discharges, BAT limits would be set equal to BPT limits
for low volume waste.
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In addition, EPA has identified some differences among the options
in terms of cost effectiveness. Section XII of this preamble describes
EPA's cost-effectiveness analysis for the preferred regulatory options.
EPA's analysis to date shows that the average cost effectiveness
($1981/TWPE) under Option 3a, 3b, 3, and 4a for existing direct
dischargers is $27, $31, $44, and $57, respectively. This demonstrates
that Option 3a is the most cost effective of the preferred options,
Option 4a is the least cost effective of the preferred options, and
Option 3 and Option 3b are between the two.
EPA also calculated the cost-effectiveness of particular controls
for the wastestreams that would be controlled under the preferred
options for existing direct dischargers.\38\ The cost-effectiveness for
zero discharge of fly ash transport and FGMC wastewater, as in Option
3a, is $27 per TWPE removed. The cost effectiveness of chemical
precipitation alone is $70 per TWPE removed, while the cost
effectiveness of chemical precipitation plus anaerobic biological
treatment, which is included in all options except Option 3a, is $60
per TWPE removed. The cost effectiveness of zero discharge of bottom
ash transport water for all units more than 50 MW is $107 per TWPE. In
comparison, when this requirement is applied only to units more than
400 MW, as in Option 4a, the cost effectiveness value is $99 per TWPE
removed.
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\38\ While it is not included in the preferred options as a
wastestream with additional controls, EPA also looked at the cost
effectiveness of controlling leachate using chemical precipitation
and this value would exceed $1,000 per TWPE removed.
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Thus, the cost effectiveness for control of the various
wastestreams included within the preferred options ranges from $27-$107
per TWPE in $1981; with zero discharge controls on fly ash transport
wastewater being the most cost-effective, zero discharge controls on
bottom ash transport wastewater being the least cost effective, and
controls for FGD wastewater based on chemical precipitation in
combination with anaerobic biological treatment between the two.
Effluent Limits for Oil-fired Generating Units. EPA is proposing to
establish BAT limits equal to BPT for existing oil-fired units. For the
purpose of the proposed BAT effluent limits, oil-fired generating units
would be those that use oil as either the primary or secondary fuel and
do not burn coal or petroleum coke. Units that use oil only during
startup or for flame stabilization would not be considered oil-fired
generating units. EPA is proposing to set BAT limits equal to BPT for
existing oil-fired units because, in comparison to coal- and petroleum
coke-fired units, oil-fired units generate substantially fewer
pollutants, are generally older and operate less frequently, and in
many cases are more susceptible to early retirement when faced with
compliance costs attributable to the proposed ELGs.
The amount of ash generated at oil-fired units is a small fraction
of the amount produced by coal-fired units. Coal-fired units generate
hundreds or thousands of tons of ash each day, with some plants
generating more than 1,500 tons per day of ash. In contrast, oil-fired
units generate less than one ton of ash per day. This disparity is also
apparent when comparing the ash tonnage to the amount of power
generated, with coal-fired units producing nearly 300 times more ash
than oil-fired units (0.04 tons per MW-hour on average for coal units;
0.000145 tons per MW-hour on average for oil units). The amount of
pollutants discharged to surface waters is roughly correlated to the
amount of ash wastewater discharged, thus oil-fired units discharge
substantially less pollutants to surface waters than a coal-fired unit
even when generating the same amount of electricity. EPA estimates that
if BAT effluent limits for oil-fired units were set equal to either the
proposed Option 3 or Option 4a limits for coal-fired units (>50 MW),
the total industry pollutant reductions attributable to the proposed
rule would increase by less than one percent.
Oil-fired units are generally among the oldest steam electric units
in the industry. Eighty-seven percent of the units are more than 25
years old. In fact, more than a quarter of the units began operation
more than 50 years ago. Based on responses to the industry survey, only
20 percent of oil-fired units operate as baseload units; the rest are
either cycling/intermediate units (45 percent) or peaking units (35
percent). These units also have notably low capacity utilization. While
a quarter of the baseload units report capacity utilization greater
than 75 percent, most baseload units (60 percent) report a capacity
utilization of less than 25 percent. Eighty percent of the cycling/
intermediate units and all peaking units also report capacity
utilization less than 25 percent. Thirty-five percent of oil-fired
units operated for more than six months in 2009; nearly half of the
units operated for less than 30 days.
As shown above, oil-fired units are generally older and operate
intermittently (i.e., they are peaking, cycling, or intermediate
units). While these oil-fired units are capable of installing and
operating the treatment technologies evaluated as part of this
rulemaking, and the costs would be affordable for most of the plants,
EPA believes that, due to the factors described here, companies may
choose to shut down these oil-fired units instead of making new
investments to comply with the rule. If these units shut down, it could
reduce the flexibility that grid operators have during peak demand
because there would be less reserve generating capacity to draw upon.
But more importantly, maintaining a diverse fleet of generating units
that includes a variety of fuel sources is vital to the nation's energy
security. Because the supply/delivery network for oil is different from
other fuel sources, maintaining the existence of oil-fired generating
units helps ensure reliable electric power generation. Thus, the oil-
fired generating units add substantially to electric grid reliability
and the nation's energy security.
Based on responses to the industry survey, EPA estimates that less
than 20 oil-fired units discharged fly ash or bottom ash transport
water in 2009. At the same time, EPA notes that many oil-fired units
operate infrequently, which could contribute to the relatively low
numbers of units discharging ash-related wastewater. Should more
widespread operation of oil units be required to meet demands of the
electric grid, additional plants may find it necessary to discharge ash
transport water. Because of the operating conditions unique to the
existing fleet of oil-fired units and potential effects on the nation's
electric power grid, a non-water quality environmental impact that EPA
considers under Section 304(b) of the CWA, EPA believes it is
appropriate to set BAT effluent limits for oil-fired equal to the
current BPT limits.
Effluent Limits for Small Generating Units. EPA is proposing to
establish
[[Page 34475]]
BAT effluent limits equal to BPT for existing small generating units,
which would be defined as those units with a total nameplate generating
capacity of 50 MW or less.\39\ Small units are more likely to incur
compliance costs that are disproportionately higher per amount of
energy produced than those incurred by large units because they are not
as able to take advantage of economies of scale. For example, the unit-
level annualized cost for the proposed FGD wastewater treatment
technology under Option 3 (chemical precipitation plus biological
treatment) is approximately seven times more expensive on a dollar-per-
megawatt basis for small generating units, relative to units larger
than 50 MW. Similarly, the unit-level annualized cost to convert the
fly ash handling system to dry technology (conveyance equipment and
intermediate storage silos) is more than four times more expensive on a
dollar-per-megawatt basis for small generating units, relative to units
larger than 50 MW. For Option 4, bottom ash conversions are more than
six times more expensive for small units, on a dollar-per-megawatt
basis.
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\39\ Preferred Option 4a would increase this threshold for
purposes of discharges of pollutants in bottom ash transport water
only, to 400 MW or less.
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Moreover, the record demonstrates that the amount of pollutants
collectively discharged by small generating units is a very small
portion of the pollutants discharged collectively for all steam
electric power plants (e.g., less than 1 percent under Option 3). As a
result, setting BAT limits equal to BPT for existing steam electric
generating units with a capacity of 50 MW or less will have little
impact on the pollutant removals for the overall rule.
EPA considered establishing the size thresholds for small
generating units at 25 MW because that threshold is already used for
this industry sector in some regulatory contexts. For example, the
Clean Air act defines an ``electric utility generating unit'' as ``any
fossil fuel fired combustion unit of more than 25 megawatts that serves
a generator that produces electricity for sale.'' CAA Section
112(a)(8), 42 U.S.C. 7412(a)(8). The existing ELGs for the steam
electric power generating point source category also include different
effluent limitations for plants with total rated generating capacity of
less than 25 MW. See 40 CFR 423.13(c)(1) and 423.15(i)(1).
EPA currently proposes a threshold of 50 MW \40\ rather than 25 MW
because the proposed 50 MW threshold would do more to alleviate
potential impacts.\41\ EPA recognizes that any attempt to establish a
size threshold for generating units will be imperfect due to individual
differences across units and firms. However, EPA believes that a
threshold of 50 MW or less reasonably and effectively targets those
generating units that should receive different treatment based on the
considerations described above. EPA requests comment on the proposed 50
MW threshold applicable to discharges of the wastestreams described
under each of the preferred options, and as well as other possible
thresholds for small units.
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\40\ For Option 4a, for bottom ash transport water only, as
explained previously, EPA is proposing to raise the value from less
than or equal to 50 MW to less than or equal to 400 MW.
\41\ As discussed in Section XVII.C, the proposed 50 MW
threshold also alleviates potential impacts which may be borne by
small entities or municipalities.
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4. Rationale for the Proposed Best Available Demonstrated Control/NSPS
Technology
Section 306 of the CWA directs EPA to promulgate New Source
Performance Standards, or NSPS, ``for the control of the discharge of
pollutants which reflects the greatest degree of effluent reduction
which the Administrator determines to be achievable through application
of the best available demonstrated control technology, processes,
operating methods, or other alternatives, including, where practicable,
a standard permitting no discharge of pollutants.'' Congress envisioned
that new sources could meet tighter controls than existing sources
because of the opportunity to incorporate the most efficient processes
and treatment systems into the facility design. As a result, NSPS
should represent the most stringent controls attainable through the
application of the best available demonstrated control technology, or
BADCT, for all pollutants (that is, conventional, nonconventional, and
priority pollutants).
After considering all of the technology options described above in
Section VII.B.2, EPA is proposing to establish NSPS based on the suite
of technologies identified for Option 4 in Table VIII-1. Thus, the
proposed NSPS would do the following:
Establish numeric effluent limits for mercury, arsenic,
selenium, and nitrate-nitrite in discharges of FGD wastewater;
Maintain the current ``zero discharge'' effluent limit for
all pollutants in fly ash transport water, and establish new ``zero
discharge'' effluent limits for all pollutants in bottom ash transport
water and FGMC wastewater;
Establish numeric effluent limits for mercury, arsenic,
selenium, and TDS in discharges of gasification wastewater;
Establish numeric effluent limits for TSS, oil and grease,
copper, and iron in discharges of nonchemical metal cleaning wastes;
and
Establish numeric effluent limits for mercury and arsenic
in discharges of leachate.
The record indicates that the proposed NSPS is technologically
available and demonstrated. The technologies that serve as the basis
for Option 4 are all available based on the performance of plants using
components of the suite of technologies within the past decade. For
example, approximately a third of plants that discharge FGD wastewater
utilize chemical precipitation (in some cases, also using additional
treatment steps). Five plants operate fixed-film anoxic/anaerobic
biological treatment systems for the treatment of FGD wastewater and
another operates a suspended growth biological treatment system that
targets removal of selenium.\42\ EPA is aware of industry concerns with
the feasibility of biological treatment at some power plants.
Specifically, industry has asserted that the efficacy of these systems
is unpredictable, and is subject to temperature changes, high chloride
concentrations, and high oxidation reduction potential in the absorber
(that may kill the treatment bacteria). EPA's record to date does not
support these assertions, but is interested in additional information
that addresses these concerns. Moreover, approximately 50 coal-fired
generating units were built within the last 20 years and most (83
percent) manage their bottom ash without using water to transport the
ash and, as a result, do not discharge bottom ash transport water. The
Option 4 technologies being proposed today represent current industry
practice for gasification wastewater. Every IGCC power plant currently
in operation uses vapor compression evaporation to treat the
gasification wastewater, even when the wastewater is not discharged and
is instead reused at the plant. In the case of FGMC wastewater, every
plant currently using post-combustion sorbent injection (e.g.,
activated carbon injection) either handles the captured spent sorbent
with a dry process or
[[Page 34476]]
manages the FGMC wastewater so that it is not discharged to surface
waters (or has the capability to do so). For leachate, as discussed
above in Section VI, chemical precipitation is a well-demonstrated
technology for removing metals and other pollutants from a variety of
industrial wastewater, including leachate from other landfills not
located at power plants. It therefore represents the ``greatest degree
of effluent reduction . . . achievable'' as that phrase is used in
section 306 of the Clean Water Act.
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\42\ Four of the six operate the biological treatment systems in
combination with chemical precipitation. Other power plants are
considering installing the biological treatment technology to remove
selenium, and at least one plant is moving forward with
construction.
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The proposed NSPS for discharges of nonchemical metal cleaning
waste are equal to the current BPT effluent limits that apply to
discharges of these wastes from existing sources. As such, the proposed
NSPS would be consistent with current industry practice for treating
nonchemical metal cleaning waste and is based on the same technology
that was used as the basis for the current NSPS for chemical metal
cleaning waste. Based on responses to the industry survey, facilities
typically treat both chemical and nonchemical metal cleaning waste in
similar fashion.
The NSPS being proposed today also poses no barrier to entry. The
cost to install technologies at new units are typically less than the
cost to retrofit existing units. For example, the cost differential
between BAT Options 3 and 4 for existing sources is mostly associated
with retrofitting controls for bottom ash handling systems. For
existing generating units, the effluent requirements considered under
Option 4a for BAT would cause those plants with units greater than 400
MW that discharge bottom ash wastewater to either modify their
processes to become a closed-loop wet sluicing system, or retrofit
modifications such as replacing the bottom of boilers to accommodate
mechanical drag chain systems. For new sources, however, Option 4 would
not present plants with the same choice of retrofit versus modification
of existing processes. This is because every new generating unit
already has to install some type of bottom ash handling system as the
unit is constructed. Establishing a zero discharge standard for
pollutants in bottom ash transport water as part of the NSPS means that
power plants will install a dry bottom ash handling system during
construction instead of installing a wet-sluicing system. EPA estimates
that over the past 20 years, more than 50 new coal-fired generating
units were built and that most of these units (83 percent) installed
dry bottom ash handling systems.
Moreover, as described above in Section XI, EPA assessed the
possible impacts of Option 4 to new units by comparing the costs of the
Option 4 technologies to the costs of a new generating unit and as part
of its Integrated Planning Model analyses. In both cases, the results
show that the incremental costs that would be imposed by Option 4 do
not present a barrier to entry. EPA estimated that the compliance costs
for a new unit (capital and O&M) represent at most 1.5 percent of the
annualized cost of building and operating a new 1,300 MW coal-fired
plant, with capital costs representing less than 1 percent of the
overnight construction costs, and annual O&M costs representing less
than 5 percent of the cost of operating a new plant. IPM results show
no barrier to new generation capacity during the model years in which
all existing plants must be in compliance as a result of the BAT/NSPS
compliance scenario.
Finally, EPA has analyzed non-water quality environmental impacts
associated with Option 4 for existing sources, and its analysis is
relevant to the consideration of non-water quality environmental
impacts associated with Option 4 for new sources. EPA's analysis
demonstrates that the non-water quality environmental impacts
associated with Option 4 for existing sources are acceptable. Given
that there is nothing inherent about a new unit that would alter the
analysis for such sources, EPA believes that the non-water quality
environmental impacts associated with the proposed NSPS regulatory
option are, likewise, acceptable.
In contrast to the best available technology economically
achievable, or BAT, that EPA is proposing today for existing sources,
the proposed NSPS would establish the same limits for oil-fired
generating units and small generating units \43\ that are being
proposed for all other new sources. A key factor that affects
compliance costs for existing sources is the need to retrofit new
pollution controls to replace existing pollution controls. New sources
do not trigger retrofit costs because the pollution controls (process
operations or treatment technology) are installed at the time the new
source is constructed. Thus, new sources are less likely than an
existing source to experience financial stress by the cost of
installing pollution controls, even if the pollution controls are
identical. EPA requests comment on its proposal to establish the same
NSPS for small generating units as for larger units.
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\43\ As a point of clarification, this similarly holds true for
bottom ash limitations.
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EPA is not proposing regulatory Options 1 or 2, which would
establish new effluent limits for only two of the seven key
wastestreams addressed by this proposed rule, as its preferred option
for NSPS. As explained above, neither of these two options represents
the greatest degree of effluent reduction which the Administrator
determines to be achievable through the best available demonstrated
control technology.
EPA also did not select any of the preferred BAT regulatory Options
(i.e., Options 3a, 3b, 3, or 4a) as its preferred option for NSPS
because they would not control FGD wastewater (Option 3a and Option 3b
for units at plants with a total wet-scrubbed capacity of less than
2,000 MW), bottom ash transport water (Option 3a, Option 3b, Option 3,
and Option 4a for units less than or equal to 400 MW) or leachate
discharges (Options 3a, 3b, 3, and 4a) and other, more effective,
available technologies exist that do not present a barrier to entry and
have acceptable non-water quality environmental impacts. EPA did not
select preferred Option 3a for the same reasons it rejected Options 1
and 2. EPA did not select Options 3b, 3, or 4a because, under these
regulatory options, NSPS effluent limits for bottom ash transport water
for all or some portion of units and leachate would be set equal to the
current BAT effluent limits on TSS and oil and grease, which are based
on using surface impoundments.\44\ The record demonstrates that zero
discharge technologies are effective and available for managing bottom
ash at new sources. Since these zero discharge technologies have been
installed at 83 percent of coal-fired units built in the last 20 years,
effluent standards based on surface impoundments do not represent Best
Available Demonstrated Control Technology to control the discharge of
pollutants in the bottom ash wastestream from new sources regardless of
the unit size. In addition, the record demonstrates that chemical
precipitation is a more effective technology than surface impoundments
for controlling the pollutants present in leachate. For these reasons,
Options 3b, 3 and 4a do not represent the best available demonstrated
control technology to control the discharge of pollutants of concern
from new sources.
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\44\ This rationale similarly applies to Option 3a.
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EPA did not select Option 5 as its preferred option for NSPS
because of its high costs, which are substantially higher than the
costs for Option 4 and the other options evaluated for NSPS. See the
TDD and RIA for more information about the estimated
[[Page 34477]]
compliance costs for the NSPS options. Also, see Section XI below. The
cost differential between Options 4 and 5 is primarily due to the
evaporation technology basis for controlling pollutants in FGD
wastewater under Option 5.
Finally, EPA notes that Option 5 is comparable to Option 4 with
respect to much of the anticipated pollutant removals, particularly the
expected removals of arsenic, mercury, selenium and nitrogen. At the
same time, Option 5 would control other pollutants in FGD wastewater
that Options 1 through 4 do not effectively control, namely boron,
bromides, and TDS. EPA is aware that bromide in wastewater discharges
from steam electric power plants located upstream from a drinking water
intake has been associated with the formation of trihalomethanes, also
known as THMs, when it is exposed to disinfectant processes in water
treatment plants. EPA recommends that permitting authorities consider
the potential for bromide discharges to adversely impact drinking water
intakes when determining whether additional water quality-based
effluent limits may be warranted. Although EPA did not select Option 5
as the preferred NSPS option, the technologies forming the basis for
Option 5 are all technologically available and may be appropriate
(individually or in totality) as the basis for water quality-based
effluent limits in individual or general permits depending on site-
specific conditions. EPA requests comment on its selection of Option 4
instead of Option 5 as the basis for NSPS.
5. Rationale for the Proposed PSES Technology
Section 307(b), 33 U.S.C. 1317(b), of the Clean Water Act requires
EPA to promulgate pretreatment standards for pollutants that are not
susceptible to treatment by POTWs or which would interfere with the
operation of POTWs. EPA looks at a number of factors in selecting the
technology basis for pretreatment standards. For existing sources,
these factors are generally the same as those considered in
establishing BAT. However, unlike direct dischargers whose wastewater
will receive no further treatment once it leaves the facility, indirect
dischargers send their wastewater to POTWs for further treatment. As
such, EPA must also determine that a pollutant is not susceptible to
treatment at a POTW or would interfere with POTW operations.
Table VIII-3 summarizes the pass through analysis results for the
BAT/NSPS pollutants for the various wastestreams and regulatory
options. As shown in the table, all of the pollutants proposed for
regulation under BAT/NSPS pass through.
Table VIII-3--Summary of Pass Through Analysis Results
------------------------------------------------------------------------
Pass through? (Yes/
Treatment option Pollutant No)
------------------------------------------------------------------------
Chemical Precipitation for FGD Arsenic.......... Yes.
Wastewater and/or Leachate. Mercury.......... Yes.
Biological (chemical Arsenic.......... Yes.
precipitation followed by Mercury.......... Yes.
anoxic/anaerobic biological) Nitrate Nitrite Yes.
for FGD Wastewater and/or as N.
Leachate.
Selenium......... Yes.
Mechanical Vapor-Compression Arsenic.......... Yes.
Evaporation for FGD Mercury.......... Yes.
Wastewater.
Selenium......... Yes.
TDS.............. Yes.
Mechanical Vapor-Compression Arsenic.......... Yes.
Evaporation for IGCC Mercury.......... Yes.
Wastewater.
Selenium......... Yes.
TDS.............. Yes.
Nonchemical Metal Cleaning Copper........... Yes.
Wastes.
------------------------------------------------------------------------
For this proposal, EPA evaluated the same model technologies and
regulatory options for PSES that it evaluated for BAT (described in
Section VIII.A.2). These standards would apply to existing generating
units that discharge wastewater to POTWs.
As explained above in Section III.B.5, in selecting the PSES
technology basis, the Agency generally considers the same factors as it
considers when setting BAT, including economic achievability.
Typically, the result is that the PSES technology basis is the same as
the BAT technology basis. This proposal is no exception. After
considering all of the technology options described in Section
VIII.A.2, as is the case for BAT, EPA is proposing four preferred
alternatives for PSES (i.e., Options 3a, 3b, 3, and 4a).
With the exception of oil-fired generating units and small
generating units (i.e., 50 MW or smaller), the proposed rule under
Option 3a would:
Establish a ``zero discharge'' effluent limit for all
pollutants in fly ash transport water and FGMC wastewater;
Establish numeric effluent limits for mercury, arsenic,
selenium, and TDS in discharges of gasification wastewater;
Establish numeric effluent limits for copper in discharges
of nonchemical metal cleaning wastes; \45\ and
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\45\ As described in Section VIII.A.3, EPA is proposing to
exempt from new BAT copper and iron effluent limits existing
discharges of nonchemical metal cleaning wastes that are currently
authorized by an NPDES permit without iron and copper limits. This
exemption also applies to any indirect discharges of nonchemical
metal cleaning waste that are authorized without copper pretreatment
standards. For such indirect discharges, the regulation would not
specify PSES.
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Establish BAT effluent limits for bottom ash transport
water and leachate that are equal to the current BPT effluent limits
for these discharges (i.e., numeric effluent limits for TSS and oil and
grease).
With the exception of oil-fired generating units and small
generating units (i.e., 50 MW or smaller), the proposed PSES under
Option 3b would:
Establish standards for mercury, arsenic, selenium, and
nitrate-nitrite in discharges of FGD wastewater for units located at
plants with a total wet-scrubbed capacity of 2,000 MW; \46\
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\46\ Under Option 3b (for units located at plants with a total
wet-scrubbed capacity of less than 2,000 MW), the regulations would
not specify PSES for FGD wastewater, and POTWs would need to develop
local limits to address the introduction of pollutants by steam
electric power plants to the POTWs that cause pass through or
interference, as specified in 40 CFR 403.5(c)(2).
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Establish a ``zero discharge'' standard for all pollutants
in fly ash transport water and FGMC wastewater;
[[Page 34478]]
Establish standards for copper in discharges of
nonchemical metal cleaning wastes; \47\ and
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\47\ As described in Section VIII.A.3, EPA is proposing to
exempt from new BAT copper and iron effluent limits existing
discharges of nonchemical metal cleaning wastes that are currently
authorized by an NPDES permit without iron and copper limits. This
exemption also applies to any indirect discharges of nonchemical
metal cleaning waste that are authorized without copper pretreatment
standards. For such indirect discharges, the regulation would not
specify PSES.
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Establish standards for mercury, arsenic, selenium and TDS
in discharges of gasification wastewater.
Under the third preferred alternative for PSES (Option 3), in
addition to the requirements described for Option 3b, the proposed rule
would establish the same standards for mercury, arsenic, selenium, and
nitrate-nitrite in discharges of FGD wastewater as for Option 3b from
units at all steam electric facilities, with the exception of oil-fired
generating units and small generating units (i.e., 50 MW or smaller).
Under the fourth preferred alternative for PSES (Option 4a), the
proposed rule would establish ``zero discharge'' effluent limits for
all pollutants in bottom ash transport water for units greater than 400
MW. All other proposed Option 4a requirements are identical to the
proposed Option 3 requirements.
EPA is putting forth Options 3a, 3b, 3, and 4a as the Agency's
preferred PSES regulatory options in order to confirm its understanding
of the pros and cons of these options through the public comment
process and intends to evaluate this information and how it relates to
the factors specified in the CWA. For the same reasons identified in
Section VIII.A.3 above for BAT, EPA's analysis to date suggests that
for indirect dischargers as well as direct dischargers, the Option 3a,
Option 3b, Option 3, and Option 4a technologies are available and
economically achievable, and that the other regulatory options (Options
1, 2, 4, and 5) do not reflect the criteria for PSES. In addition, EPA
has determined that these standards will prevent pass-through of
pollutants from POTWs into receiving streams and also help control
contamination of POTW sludge. EPA also considered the non-water quality
environmental impacts and found them to be acceptable, as described in
Section XV. Furthermore, for the same reasons that apply to EPA's
preferred BAT options and described in Section VIII.A.3, with the
exception of numeric standards for copper in discharges of nonchemical
metal cleaning wastes,\48\ EPA is proposing not to subject discharges
from oil-fired generating units and small generating units (i.e., 50 MW
or smaller \49\) to POTWs to requirements based on Options 3a, 3b, 3,
or Option 4a.
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\48\ EPA is proposing to exempt from new PSES copper standards
for existing discharges of nonchemical metal cleaning wastes that
are currently authorized. For these discharges, the regulation would
not specify PSES.
\49\ Preferred Option 4a would increase this threshold for
purposes of discharges of pollutants in bottom ash transport water
only, to 400 MW or less.
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Finally, similar to EPA's preferred BAT options and for the reasons
supporting those options, for certain wastestreams, EPA is proposing
that any new PSES discharge standards would apply to discharges of the
regulated wastewater generated after July 1, 2017. See discussion in
Section XVI.
6. Rationale for the Proposed PSNS Technology
Section 307(c) of the CWA, 33 U.S.C. 1317(c), authorizes EPA to
promulgate pretreatment standards for new sources (PSNS) at the same
time it promulgates new source performance standards (NSPS). As is the
case for PSES, PSNS are designed to prevent the discharge of any
pollutant into a POTW that may interfere with, pass through, or may
otherwise be incompatible with POTWs. In selecting the PSNS technology
basis, the Agency generally considers the same factors it considers in
establishing NSPS along with the results of a pass through analysis. As
a result, EPA typically promulgates pretreatment standards for new
sources based on best available demonstrated technology for new
sources. See National Ass'n of Metal Finishers v. EPA, 719 F.2d 624,
634 (3rd Cir. 1983). The legislative history explains that Congress
required simultaneous establishment of new source standards and
pretreatment standards for new sources for two reasons. First, Congress
wanted to ensure that any new source industrial user achieve the
highest degree of internal effluent controls necessary to ensure that
such user's contribution to the POTW would not cause a violation of the
POTW's permit. Second, Congress wished to eliminate from the new user's
discharge any pollutant that would pass through, interfere, or was
otherwise incompatible with POTW operations.
For this proposal, EPA evaluated the same model technologies and
regulatory options for PSNS that it evaluated for NSPS (described above
in Section VIII.A.4). These standards would apply to new generating
units or new facilities that discharge wastewater to POTWs. After
considering all of the technology options described in Section
VIII.A.2, as is the case for NSPS, EPA is proposing to establish PSNS
based on the technologies specified in Option 4. The proposed PSNS
would:
Establish standards for mercury, arsenic, selenium, and
nitrate-nitrite in discharges of FGD wastewater;
Maintain a ``zero discharge'' standard for all pollutants
in fly ash transport water, and establish a zero discharge standard for
bottom ash transport water and FGMC wastewater;
Establish standards for mercury, arsenic, selenium and TDS
in discharges of gasification wastewater;
Establish standards for copper in discharges of
nonchemical metal cleaning wastes; and
Establish standards for mercury and arsenic in discharges
of leachate.
For the same reasons identified for NSPS in Section VIII.A.4, EPA
is proposing Option 4 as its preferred option because the technologies
forming the basis for that option are available and demonstrated and
will not pose a barrier to entry.\50\ In addition, EPA has determined
that these standards will prevent pass-through of pollutants from POTWs
into receiving streams and also help control contamination of POTW
sludge. EPA also considered the non-water quality environmental impacts
associated with the preferred option and found them to be acceptable,
as described in Section XV.
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\50\ For the same reasons discussed above in Section VIII for
NSPS, EPA similarly determined the other regulatory options do not
reflect PSNS.
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7. Consideration of Future FGD Installations on the Analyses for the
ELG Rulemaking
As explained earlier, implementation of air pollution controls may
create new wastewater streams at power plants. The analyses and the
findings on economic achievability presented in this preamble reflect
consideration of wastestreams generated by air pollution controls that
will likely be in operation at plants at the time EPA takes final
action on this rulemaking. However, EPA recognizes that some recently
promulgated Clean Air Act requirements, along with state requirements
or enforcement actions, may lead to additional air pollution controls
(and resulting wastestreams) at existing plants beyond this date. In an
effort to assess the economic achievability of the proposed rule in
such cases, EPA also conducted a sensitivity analysis that forecasts
future installations of air controls through 2020 \51\ and the
associated costs of
[[Page 34479]]
complying with these proposed regulatory requirements for the
wastewater that may result from the forecasted air control
installations. The sensitivity analysis and results are described in
more detail in DCN SE01989.
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\51\ EPA considers that by forecasting future installations of
controls out to the year 2020, the sensitivity analyses for this
rulemaking reasonably reflect full implementation of air pollution
controls to comply with existing federal and state requirements.
---------------------------------------------------------------------------
EPA has two primary data sources upon which to make its projections
of future air control installations: 1) Integrated Planning Model
estimates for the final MATS rule; \52\ and 2) responses to EPA's steam
electric industry survey. At the time EPA promulgated the MATS rule in
2011, it projected air pollution control retrofits using IPM (which
also included projected retrofits for CSAPR). To support this
rulemaking, EPA surveyed the industry about its plans for installing
certain new air pollution controls at facilities through 2020. EPA has
no reason to conclude that either the IPM FGD projections or the survey
projections are more accurate than the other. In fact, both of these
sources may overstate actual installations. Prior to MATS becoming
final, many plant owners and operators assumed that wet scrubbers would
be the only technology available to meet emissions limits for acid
gases. As EPA gathered and published additional data on facility
emission rates (which informed how the Agency set the standards), and
as stakeholders researched and published additional information on the
performance of less capital-intensive control technologies such as dry
sorbent injection, it has become clear that many facilities will find
it more cost-effective to forgo wet scrubbers in favor of other
emission-reduction strategies. Furthermore, major economic variables
such as electricity demand and natural gas prices have changed
substantially since the prevailing market conditions in 2010, when
respondents were answering the survey. For example, a facility
originally indicating an expectation in the industry survey to install
a wet scrubber by 2020 may now find itself no longer competitive in the
updated marketplace with substantially lower natural gas prices and
lower electricity demand growth than previously expected. Consequently,
the facility may elect to retire and thereby neutralize the previously
reported intent to scrub. Nevertheless, these two sources remain the
best available information EPA has with which to estimate future
conditions.
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\52\ EPA IPM v.4.10 projections for units based on compliance
with CSAPR, MATS, state rules, and enforcement actions including
consent decrees.
---------------------------------------------------------------------------
As a first step in conducting a sensitivity analysis, EPA compared
the projections from the two sources described above. This comparison
demonstrates that the IPM results for the MATS Policy Case and the ELG
industry survey responses are consistent at the aggregate level.
Furthermore, in very large part, both the survey and IPM identify the
same generating units as being wet-scrubbed, either currently or in the
future (the two sources are in agreement for approximately 94 percent
of the wet-scrubbed units). The two sources also project similar wet-
scrubbed capacities. In the very few cases where there are differences
between the two sources, the differences are primarily due to the
expected variation at a unit-level (e.g., IPM projects wet FGD at unit
A and dry FGD at unit B, but instead the survey responses report wet
FGD at unit B and dry FGD at unit A). Another difference between the
MATS IPM estimates and the industry survey estimates is that, in a very
few cases, the IPM results estimate that certain plants would retire
(and therefore would not install wet scrubbers). In conducting the
analyses for the ELG, EPA made the conservative assumption (i.e., one
that would tend to overestimate cost, if anything) that a plant would
still be in operation in 2020 unless the plant has formally announced
its closure by 2014.
Because its goal in conducting this sensitivity analysis was to
assess the economic achievability of the proposed ELG, even in light of
possible future air controls, EPA developed a conservative upper bound
estimate of future installations by combining the results of the two
sources to develop its ``future steam profile.'' In other words, EPA
combined any source that reported or projected a wet FGD into one
``future steam profile.'' This ``future steam profile'' is conservative
because it reflects more wet FGDs than are anticipated to actually be
installed; that is, by aggregating the survey and IPM forecast
estimates it results in a total number of wet FGD systems and wet-
scrubbed capacity that is greater than either of those individual
sources. EPA then added costs associated with projected wastewater
discharges from this future steam profile to comply with this proposal
to the total costs it previously calculated for the existing universe.
Based on the results of this conservative analysis, EPA finds that
discharges from these additional air controls (which, if actually
installed, would be due to various requirements including state rules,
consent decrees, CSAPR/CAIR, and MATS) may increase the costs of this
proposed rule by no more than 10 to 15 percent. See discussion in
Section VII.A.7. Even if all of these additional costs were to come to
fruition, which is unlikely since the ``future steam profile''
overestimates the number of new wet FGD systems that are anticipated,
EPA finds that these additional costs are economically achievable.
EPA notes that subsequent to its analysis, the D.C. Circuit Court
of Appeals vacated the CSAPR. EPA will continue to assess the potential
impacts that changes to air pollution regulations may have on future
installations of wet FGD systems. For the purpose of FGD wastewater
analyses for this rulemaking, EPA has made a conservative assumption
that all of the previously projected wet scrubber additions in the
CSAPR-inclusive baseline (which also included MATS, state rules,
consent decrees, etc.) would continue to be built, and that discharges
from those additional wet scrubbers would therefore be subject to the
proposed revisions to the ELGs.
8. Timing of New Requirements
As part of its consideration of technological availability and
economic achievability, EPA considered the magnitude and complexity of
process changes and new equipment installations that would be required
at many existing facilities to meet the requirements of the rule. As
discussed in Section VIII.A.2, EPA proposes that certain BAT
limitations for existing sources being proposed today (those that would
establish requirements more stringent than existing BPT requirements)
would apply on a date determined by the permitting authority that is as
soon as possible when the next permit is issued beginning July 1, 2017
(approximately three years from the effective date of this rule). This
is true of the proposed limitations and standards based on any of the
eight main regulatory options, including the preferred options, Option
3a, Option 3b, Option 3, or Option 4a.
EPA is proposing this approach for several practical reasons. While
some facilities already have the necessary equipment and processes in
place, or could do so relatively quickly, and may need little time
before they are able to comply with the revised ELG requirements, not
all will be able to do so. Some facilities will need time to raise the
capital, plan and design the system, procure equipment, construct and
then test the system. Moreover, providing a window of time will better
enable facilities to install the pollution control technology during an
otherwise
[[Page 34480]]
planned shutdown or maintenance period. In some cases, a facility must
apply for permission to enter into such a period where they are
producing no or less power.
During site visits, EPA found that most facilities need several
years to plan, design, contract, and install major system
modifications, especially if they are to be accomplished during planned
maintenance periods to avoid causing forced outages. EPA recognizes
that the proposed rule would require a significant amount of system
design by engineering firms, equipment procurement from vendors, and
installation by trained labor forces. EPA anticipates that changes to
FGD wastewater treatment systems, fly ash system, bottom ash systems,
and/or leachate treatment systems would constitute major system
modifications requiring several years to accomplish for many plants.
EPA identified certain technical and logistical issues at some
facilities that may warrant additional time, such as coordinating ash
system conversions for multiple generating units. In order to avoid any
impacts on the consistency and reliability of power generation, outages
at multiple facilities in one geographic area would need to be
coordinated, which could also result in the need for more time.
EPA recognizes that permitting authorities have discretion with
respect to when to reissue permits and can take into consideration the
need to provide additional time to include BAT limits to prevent or
minimize forced outages. Thus, in some cases, the new BAT requirements
may as a practical matter be applied to a facility sometime after July
1, 2017. However, EPA judges that, under this proposed approach, all
steam electric facilities will have the proposed BAT limitations
applied to their permits no later than July 1, 2022, approximately 8
years from the date of promulgation of any final ELGs. For indirect
discharges, except with respect to discharges of nonchemical metal
cleaning waste, the proposed PSES requirements would apply by the date
determined by the control authority that is as soon as possible
beginning July 1, 2017, or approximately three years after promulgation
of any final ELGs. EPA's record indicates it may not take that long for
all facilities to meet the limitations and standards. Some plants may
not require a major modification for one or more systems to be able to
comply with new effluent limits and therefore would need less time. For
example, some plants have installed dry fly ash handling systems that
have capacity to handle all generated ash dry, yet they also maintain a
wet ash handling system as a backup. The backup wet system is typically
operated only a few days per year. According to the industry survey,
plants such as these could quickly cease operation of the wet system,
complying with a zero discharge requirement with relative ease.
EPA envisions that each facility subject to this proposal would
study available technologies and operational measures, and subsequently
install, incorporate and optimize the technology most appropriate for
each site. EPA believes the proposed rule affords flexibility for a
reasonable amount of time to conduct engineering studies, assess and
select appropriate technologies, apply for necessary permits, complete
construction, and optimize the technologies' performance. The
permitting authority could establish any additional interim milestones,
as appropriate, within these timelines.
IX. Technology Costs and Pollutant Reductions
This section provides an overview of EPA's approach for estimating
the compliance costs and pollutant reductions associated with the
regulatory options discussed in this proposal. Sections 9 and 10 of the
TDD provide a much more in depth discussion of these analyses.
EPA often estimates costs and pollutant loads on a per plant basis
and then sums or otherwise escalates the plant-specific values to
represent industry-wide compliance costs and pollutant reductions.
Calculating costs and loads on a per plant basis allows EPA to account
for differences in plant characteristics such as types of processes
used, wastewaters generated and their flows/volumes and
characteristics, and wastewater controls in place (e.g., BMPs and end-
of-pipe treatment). EPA took this approach in estimating the compliance
costs and pollutant reductions associated with this proposed rule.
EPA estimated the costs to steam electric power plants--whose
primary business is electric power generation or related electric power
services--of complying with the proposed ELGs. EPA evaluated the costs
of this proposal on all plants currently subject to the existing ELGs.
Some aspects of this proposal (e.g., applicability changes) would
likely not lead to increased costs to complying facilities. Other
aspects of this proposal would likely lead to increased costs to a
subset of complying facilities. These facilities are generally those
that generate and discharge the wastestreams for which EPA is proposing
new limitations or standards. EPA reviewed the steam electric industry
for all facilities that generate the specific types of wastewater
streams for which EPA evaluated additional limitations or standards.
The following describes the detailed costing and loadings evaluation
EPA performed for these plants.
As discussed earlier in this preamble, EPA proposes to establish a
separate set of requirements for existing oil-fired generating units
and units with a capacity of 50 MW or less. For these units, EPA is
proposing to establish BAT limitations that would be set equal to BPT
limitations. Since this proposed rule would not establish additional
control on discharges associated with these operations, there would be
no incremental costs for these units to comply with the requirements of
this proposed rule.\53\
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\53\ EPA did estimate costs for these existing oil-fired
generating units and small generating units to comply with the
options considered in this rulemaking and has included those
estimates in the docket for the proposed rule (see DCN SE01957,
Incremental Costs and Pollutant Removals for Proposed Effluent
Limitations Guidelines and Standards for the Steam Electric
Generating Point Source Category).
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For the aspects of these proposed regulatory options that include
limitations and standards for additional pollutants, EPA estimated
compliance costs and pollutant reductions from data collected through
survey responses, site visits, sampling episodes, and from individual
power plants and equipment vendors. EPA used this information to
develop computerized cost and pollutant loadings models for each of the
technologies that form the basis of the regulatory options. EPA used
these models to calculate facility-specific compliance costs and
pollutant reductions for all power plants that the information suggests
may incur costs to comply with one or more proposed limitations or
standards associated with the regulatory options.54 55
Therefore,
[[Page 34481]]
EPA's plant-specific cost and pollutant reduction estimates represent
the incremental costs/pollutant reductions for a plant when its
existing practices would not lead to compliance with the option being
evaluated for the proposed rule. While plants would not be required to
implement the specific technologies that form the basis for the
proposed limitations and standards for each of the regulatory options,
EPA calculated the cost and associated pollutant reductions for plants
to implement these technologies to estimate the compliance costs and
pollutant loading reductions associated with EPA's proposed rule.
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\54\ Because EPA anticipates taking final action on this
rulemaking in 2014, EPA did not include plants that are expected to
retire by 2014 and plants that do not discharge any of the
applicable wastestreams. Since this timeframe is approximately one
year following the date of the proposed rule, EPA considers there to
be sufficient certainty regarding plant/unit retirements or relevant
major system modifications for it to be reasonable for EPA to take
into account in the regulatory analyses for this rulemaking,
Retirements and modifications occurring farther into the future than
2014 become more uncertain and subject to change; thus, EPA has
considered such future changes, as appropriate, in sensitivity
analyses for proposed rule. However, this approach can result in
estimating compliance costs for generating units that companies have
announced will retire, repower, or convert from wet to dry ash
handling. Because of this, EPA is considering using alternative
dates, such as 2022 which may better reflect the implementation
timeframe for the ELG, for the baseline year for its analyses for
the final rule.
\55\ EPA is considering establishing BMPs that would apply to
surface impoundments that receive, store, dispose of, or are
otherwise used to manage coal combustion residuals including FGD
wastes, fly ash, bottom ash (which includes boiler slag), leachate,
and other residuals associated with the combustion of coal to
prevent uncontrolled discharges from these impoundments. Costs for
the industry to implement the BMPs under consideration are included
in EPA's cost and economic analyses for the proposed rule.
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EPA's cost estimates include two key cost components: Capital costs
(one-time costs) and operating and maintenance (O&M) costs (which are
incurred every year). Capital costs comprise the direct and indirect
costs associated with the purchase, delivery, and installation of
pollution control technologies. Capital cost elements are specific to
the industry and commonly include purchased equipment and freight,
equipment installation, buildings, land, site preparation, engineering
costs, construction expenses, contractor's fees, and contingency.
Annual O&M costs comprise all costs related to operating and
maintaining the pollution control technologies or performing BMPs for a
period of one year. O&M costs are also specific to the industry and
commonly include costs associated with operating labor, maintenance
labor, maintenance materials (routine replacement of equipment due to
wear and tear), chemical purchase, energy requirements, residual
disposal, and compliance monitoring. In some cases, the technology
options may also result in recurring costs that are incurred less
frequently than annually (e.g., 3-year recurring costs) or one-time
costs other than capital investment (e.g., one-time engineering costs).
A. Methodology for Estimating Plant-Specific Costs
The limitations and standards associated with the regulatory
options for this proposed rule address various wastestreams and, as
such, consist of multiple technology bases (see Table IX-1). As a first
step in estimating costs to control discharges associated with a
particular generating unit at an existing steam electric power plant
subject to this rulemaking (i.e., existing sources), EPA used the
plant's survey response to determine if the wastestreams it discharges
may be affected by the limitations and standards for the regulatory
options considered in this rulemaking. Then, for each of the
wastestreams that may be affected by an option, EPA reviewed the
industry survey response, available sampling data, and industry long-
term self-monitoring data to determine if the plant currently meets the
performance level of the technology basis for the requirement of an
option for that wastestream. A portion of the steam electric industry
has already implemented processes or treatment technologies that serve
as the basis for the regulatory options considered for the proposed
rule; as a result, these facilities would not incur costs to comply
with the proposed rule, or would incur costs lower than they would be
if the processes/technologies had not already been implemented. In such
cases, EPA assigned no compliance cost associated with the discharge of
that particular wastestream other than compliance monitoring costs. For
all other applicable wastestreams, EPA assessed the operations and
treatment system components in place at the plant, identified necessary
components that the plant would need to come into compliance, and
estimated the cost to install and operate those components. Table IX-2
presents a list of the major cost components included in the
evaluation. As appropriate, EPA also accounted for expected reductions
in the plant's costs associated with their current operations or
treatment systems that would no longer be needed as a result of
installing and operating the technology bases (e.g., avoided costs to
manage surface impoundments). For plants that may already have certain
components installed, EPA compared certain key operating
characteristics, such as chemical addition rates, to determine if
additional costs (e.g., chemical costs) were warranted.
Table IX-1--Technology Cost Modules Used to Estimate Compliance Costs
--------------------------------------------------------------------------------------------------------------------------------------------------------
Regulatory option
Wastestream Technology cost modules -----------------------------------------------------------------------
1 3a 2 3b 3 4a 4 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
FGD Wastewater................................ Chemical Precipitation.......... X ....... X X X X X X
Biological Treatment............ ....... ....... X X X X X
Vapor-Compression Evaporation... ....... ....... ....... ....... ....... ....... ....... X
Fly Ash Transport Water....................... Dry Fly Ash Handling............ ....... X ....... X X X X X
Bottom Ash Transport Water.................... Dry Bottom Ash Handling......... ....... ....... ....... ....... ....... X X X
Leachate...................................... Chemical Precipitation.......... ....... ....... ....... ....... ....... ....... X X
Gasification Wastewater....................... Vapor-Compression Evaporation... X X X X X X X X
Flue Gas Mercury Control Wastes............... Dry Handling.................... ....... X ....... X X X X X
--------------------------------------------------------------------------------------------------------------------------------------------------------
Other Plant-Level Costs
--------------------------------------------------------------------------------------------------------------------------------------------------------
Solids Transportation........... X X X X X X X X
Solids Disposal................. X X X X X X X X
Impoundments.................... X X X X X X X X
Compliance Monitoring........... X X X X X X X X
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 34482]]
Table IX-2--Major Capital Cost Components Included in Compliance Costs
------------------------------------------------------------------------
Technology module Major capital cost components
------------------------------------------------------------------------
Chemical Precipitation................. Equalization tank;
Reaction tanks;
Chemical feed systems;
Solids contact
clarifier;
Sand filters;
Treated wastewater
tank;
Sludge filter press;
and
Sludge holding tank.
Biological Treatment................... Bioreactor tanks;
Nutrient feed system
and storage;
Backwash system and
backwash wastewater tank; and
Heat exchangers (if
needed).
Vapor-Compression Evaporation.......... Water softener;
Brine concentrator;
and
Forced-circulation
crystallizer.
Conversion of Wet Fly Ash Handling to Conveyance Vacuum Line
Dry Vacuum Fly Ash Handling. Components (i.e., valves,
piping, couplings);
Filter-Receiver;
Vacuum Pumps;
Lot miscellaneous
instrumentation and control;
Steel or concrete
silo;
Silo Instrumentation
and Aeration System; and
Pugmill unloaders.
Conversion of Wet Bottom Ash Handling Water bath trough;
to Mechanical Drag System (MDS) or
Remote MDS.
Chain conveyor;
Inclined conveyor;
Storage silo;
Remote MDS only:
collection sump, chemical feed
system, and recirculation
pumps.
Transportation......................... Only operating and
maintenance cost components
Disposal............................... On-Site Disposal:
Landfill expansion
construction
Leachate treatment
system
Groundwater wells
Closure cap
Off-Site Disposal: no
capital cost components
Compliance Monitoring.................. Only operating and
maintenance cost components
------------------------------------------------------------------------
For example, to comply with BAT regulatory Option 4 presented in
this proposal, EPA estimated compliance costs for a plant that
currently sluices fly ash to an ash impoundment and subsequently
discharges that fly ash transport water. In this case, EPA estimated
the cost for the plant to convert its fly ash handling system to a dry
vacuum system and assumed that certain components of its existing
system would continue to be used following the conversion.\56\ EPA also
included costs for additional equipment, such as vacuum systems and
silos, to handle and store the dry fly ash. EPA also included
additional transportation and landfill disposal costs and cost savings
for managing less waste through the ash impoundment(s).
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\56\ The conversion from wet to dry fly ash handling for a unit
requires new equipment to pneumatically convey the ash; however, ash
handling vendors stated that for dry vacuum retrofits, the existing
hopper equipment and branch lines can be retained and reused.
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As another example, EPA estimated compliance costs to comply with
BAT regulatory Option 4 for a plant that currently treats its FGD
wastewater through a chemical precipitation system prior to discharge.
In this case, EPA evaluated 1) whether the chemical precipitation
system design basis included equalization with 24-hour residence time,
2) if the plant had an equivalent number and/or type of reaction tanks,
and 3) if the plant already had components such as chemical feed
systems, solids contact clarification, sand filtration, effluent and
sludge holding tanks, sludge filter press, and pumps in place. If the
plant had any of these components in place, EPA did not include that
cost in its compliance cost estimate. EPA also evaluated whether
chemical addition costs would be required based on the plant's reported
chemical addition and dosages, and estimated the costs for installing
and operating the biological treatment stage.
Following the evaluation of treatment in place, EPA estimated plant
and wastestream specific incremental costs using computerized design
and cost models. For the applicable wastestreams, the models provide
capital, annual O&M, one-time, and 3-, 5-, 6-, and 10-year recurring
costs for implementing and using the applicable technology basis. EPA
developed cost equations from responses to the industry survey,
published information, vendor contacts, and engineering judgment. EPA
developed the following cost modules:
One-Stage Chemical Precipitation--calculates capital and
O&M costs associated with a one-stage chemical precipitation system;
Biological Treatment--calculates capital and O&M costs
associated with an anoxic/anaerobic biological treatment system;
Vapor-Compression Evaporation--calculates capital and O&M
costs associated with a vapor-compression evaporation system;
Dry Fly Ash Handling--calculates capital, O&M, and
recurring costs associated with a dry fly ash handling system;
[[Page 34483]]
Dry Bottom Ash Handling--calculates capital, O&M, and
recurring costs associated with a dry bottom ash handling system;
Transportation--calculates O&M costs associated with
transporting FGD, ash, and/or landfill leachate solid waste to an on-
site or off-site landfill;
Disposal--calculates capital and O&M costs associated with
disposing of FGD, ash, and/or landfill leachate solid waste in an on-
site or off-site landfill; and
Impoundment Costs--calculates capital, O&M, and recurring
costs associated with the operation and maintenance of an on-site
impoundment.
Ultimately, the cost model produces a plant-level summary of the
incremental technology option costs associated with each regulatory
option. Each plant incurring a cost for an evaluated wastestream is
presented in the output. To determine the total compliance cost for a
plant associated with a regulatory option, EPA calculated the various
cost components described above for each applicable wastestream. EPA
then summed the costs for each component of each wastestream to
calculate the total capital, O&M, and other recurring costs for the
plant. Section XI of this preamble and the RIA contains a more detailed
discussion of EPA's annualization of the compliance costs.
EPA also evaluated the expected costs of compliance for new
sources. The construction of new generating units may occur at an
existing power plant or at a new plant construction site. The
incremental cost associated with complying with the proposed NSPS and
PSNS options will vary depending on the types of processes,
wastestreams, and waste management systems that the plant would have
installed in the absence of the proposed new source requirements. EPA
estimated capital and O&M costs for several scenarios that represent
the different types of operations that are present at existing units at
existing power plants or are typically included at new power plants.
These scenarios captured differences in the plant status (i.e.,
building a unit at a new location versus adding a new unit at an
existing power plant), presence of on-site impoundments or landfills,
type of ash handling, type of FGD systems in service, and type of
leachate collection and handling.
Finally, EPA recognizes there are significant drivers including
federal, state, and local requirements for future air control
installations at existing units. As such, EPA also conducted a
sensitivity analysis that forecasts future installations of air
controls through 2020 \57\ and the associated costs of the regulatory
options discussed in this proposal. EPA estimated these installations
using data reported by individual plants in the survey regarding
planned installations, as well as analyses conducted by OAR using the
IPM, which is widely used by EPA for analysis of rules and policies
affecting electric power generating facilities. Section VIII.A.7
contains a discussion of EPA's approach for forecasting future
installations. EPA then estimated plant-specific costs for these future
installations, using the same approach as it used for current
operations.
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\57\ EPA expects that plants will be in compliance with new
federal and state air pollution control requirements by 2020.
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B. Methodology for Estimating Plant-Specific Pollutant Reductions
EPA took a similar approach to the one described above for costs in
estimating pollutant reductions associated with the limitations and
standards for the regulatory options in this proposal. That is, EPA
estimated incremental pollutant reductions for discharges of a
particular wastestream at a particular plant when its existing
practices would not lead to compliance with the option being evaluated.
In such cases, EPA estimated the annual pollutant (baseline) load
associated with the current discharge of a wastestream and the post-
compliance annual pollutant load expected after implementation of the
applicable technology basis. EPA then calculated the pollutant loading
reduction at a particular plant as the sum of the difference between
the estimated baseline and post-compliance discharge load for each
applicable wastestream.
The following provides a brief discussion of the methodology EPA
used to estimate baseline loads discharged for the various
wastestreams. For those plants that discharge indirectly to POTWs, EPA
adjusted the baseline loads to account for pollutant removals expected
from POTWs. These adjusted pollutant reductions for indirect
dischargers reflect reductions in discharges to receiving waters.
1. FGD Wastewater
For FGD discharges, EPA estimated baseline loadings by assigning
pollutant concentrations based on the type of treatment system
currently in place at the plant. EPA assigned treatment in place for
this wastestream to one of four classes of treatment: surface
impoundment, chemical precipitation, anaerobic/anoxic biological
treatment, and vapor-compression evaporation. EPA identified the
plant's current treatment system using data reported in the industry
survey. Of the 117 plants that discharge FGD wastewater, 40 operate
chemical precipitation systems, six operate biological treatment
systems, and two operate a vapor-compression evaporation system.\58\
All other plants are categorized in the surface impoundment class of
treatment.
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\58\ A third power plant is currently installing a vapor-
compression evaporation system to treat the FGD wastewater.
---------------------------------------------------------------------------
EPA then estimated the average baseline pollutant effluent
concentration of each analyte for each class of treatment. EPA used
data collected in its sampling program to characterize effluent
concentrations from chemical precipitation, anoxic/anaerobic biological
treatment, and vapor-compression evaporation systems. Because EPA
lacked data on pollutant effluent concentrations associated with FGD
wastewater impoundments, EPA estimated that surface impoundments remove
particulate matter (including the particulate phase metals) to an
equivalent treatment level of 30 mg/L TSS (i.e., thus assuming that the
discharge would be in compliance with the current BPT effluent limits
for low-volume waste sources). EPA estimated that all dissolved metals
will pass through the surface impoundment and be discharged. Section 10
of the TDD contains more information on baseline pollutant effluent
concentrations.
EPA then used this average baseline pollutant effluent
concentration with plant-specific discharge flow rates reported in the
industry survey to estimate the mass pollutant discharged per
plant.\59\ Section 9 of the TDD contains more details on how EPA
developed flow rates.
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\59\ In some cases, plant-specific discharge flow rates were not
available in the survey response. See Section 9 of the TDD for more
information on how EPA estimated flow rates.
---------------------------------------------------------------------------
For post-compliance FGD pollutant loading concentrations, for each
pollutant, EPA used the long-term average for the technology basis for
the option being evaluated. With a few exceptions, EPA then used these
pollutant concentrations in combination with the same plant-specific
discharge flow rates it used for baseline. The exceptions are five
plants currently discharging FGD wastewater that EPA predicts will
incorporate recycle within the FGD system based on the maximum
operating chlorides concentration compared to the design maximum
chlorides concentration.
[[Page 34484]]
2. Fly Ash and Bottom Ash
For baseline ash loads, EPA used publicly available data to
characterize discharges from ash impoundments, including data collected
during EPA's Detailed Study, EPRI PISCES reports, permit application
data, and the 1982 Development Document for Final Effluent Limitations
Guidelines, New Source Performance Standards, and Pretreatment
Standards for the Steam Electric Point Source Category (EPA 440-1-82-
029). EPA used the concentration data obtained from these sources to
calculate the average pollutant concentration in fly ash, bottom ash,
and combined ash impoundments. EPA then coupled these concentrations
with plant-specific ash sluice rates reported in the industry survey to
calculate baseline ash discharge loads. In cases where EPA had
available information regarding recycle associated with the impoundment
overflow, EPA adjusted the sluice rates to reflect the discharge flow
rate from the impoundment. For post-compliance pollutant loadings, EPA
assumed implementation of dry ash handling would result in a zero post-
compliance load.
3. Combustion Residual Leachate
For baseline leachate loads, EPA used data reported in Part G of
the industry survey to calculate an average baseline pollutant
concentration for leachate. These data included responses from 22
active fuel combustion residual landfills and four inactive fuel
combustion residual landfills. EPA then used the baseline pollutant
concentrations in conjunction with leachate flow rates to calculate the
baseline pollutant loadings. Section 9 of the TDD describes how EPA
used industry survey data to estimate leachate flow rates. For post-
compliance leachate loads, EPA lacked data on effluent concentrations
from chemical precipitation or biological treatment of leachate from
combustion residual landfills or surface impoundments. EPA is proposing
the effluent limits for leachate discharges would be based on
transferring the effluent limits calculated for FGD wastewater using
the identical technology bases. Therefore, EPA estimates, based on
engineering judgment, that post-compliance effluent concentrations for
leachate would be equal to the average effluent FGD wastewater
concentrations for a similar treatment technology.
4. FGMC and Gasification Wastewaters and Nonchemical Metal Cleaning
Wastes
FGMC wastewater originates from activated carbon injection systems.
EPA identified 73 plants with current or planned activated carbon
injection systems. Most of these plants use, or plan to use, a dry
handling system to transfer the mercury-containing carbon to silos for
temporary storage until the waste is hauled away by trucks for disposal
in a landfill. EPA identified only six plants that transport (sluice)
FGMC waste with water to a surface impoundment. However, five of these
six plants do not discharge any FGMC wastewater and the remaining plant
has the capability to handle the FGMC waste using a dry system but
sometimes uses a wet system instead. Since the current baseline
discharge of pollutants for FGMC wastewater is essentially zero, the
proposed rule would establish effluent limitations that are consistent
with the current industry practices for FGMC wastewater (i.e., zero
discharge) and therefore EPA estimates there will be no (or little)
incremental removal of pollutants relative to current practices. At the
same time, however, establishing the proposed zero discharge standard
for FGMC wastewater will ensure that future FGMC installations
implement dry waste handling practices or manage wastewater in a manner
that achieves zero discharge of pollutants.
The two IGCC plants currently operating in the United States
already use the technology that is the basis for all eight regulatory
options for gasification wastewater. A third IGCC plant that will soon
begin commercial operation will also use this same treatment
technology. Since these plants are already operating the technology
that serves as the basis for the proposed BAT, the proposed rule would
establish effluent limitations that are consistent with the current
industry practices for gasification wastewater and, therefore, EPA
estimates there will be no incremental removal of pollutants relative
to current practices.
The proposed ELGs for discharges of nonchemical metal cleaning
waste are equal to the current BPT effluent limits for metal cleaning
waste. The proposed requirements are based on the same technology that
was used as the basis for the current ELGs requirements for chemical
metal cleaning waste. Since, as described above in Section VIII,
nonchemical metal cleaning waste is included within the definition of
metal cleaning waste, EPA would be establishing ELGs that are equal to
the BPT limits that already apply to discharges of these wastes to
surface waters.\60\ Additionally, as described in Section VIII.A.3, EPA
is proposing to exempt from new copper and iron limitations and
standards any existing nonchemical metal cleaning wastes generated and
currently authorized for discharge without copper and iron limits. As a
result, all facilities are either already in compliance or will be
exempt from the requirements; therefore, no facilities would incur
incremental costs to comply with the proposed ELGs for these wastes,
nor would there be incremental pollutant removals associated with the
proposed ELGs.
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\60\ The proposed BAT would establish limits for copper and iron
equal to the existing BPT limits for these pollutants. The proposed
NSPS would establish standards for copper, iron, TSS, and oil and
grease that are equal to the BPT limits for these pollutants. The
proposed PSES and PSNS would establish standards for copper equal to
the BPT limits for copper. See Section VIII for details about the
proposed limitations for nonchemical metal cleaning wastes.
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5. Request for Comment on Data
While EPA is soliciting comment on all aspects of this proposal,
the Agency would like to highlight certain aspects related to the
pollutant removal estimates. EPA solicits additional data or
information on pollutant loadings in steam electric power plant
wastewater discharges that would corroborate or correct the data used
in EPA's analysis, including data or information relating to the
pollutants of concern that EPA has identified in this rulemaking. It is
important that EPA have data and information of sufficient quality in
order to incorporate the data into its analysis. If you have data or
information or you intend to collect data that you believe would be
relevant to EPA and you would like to submit the data as part of your
public comments, EPA encourages you to contact the Agency first to
ensure that the data submitted contains sufficient and relevant
information, and that it is provided in an appropriate format, such
that it can inform EPA's analyses for the final action (see points of
contact in the introduction to this preamble).
EPA is also seeking comment related to the data used in developing
this proposed rule and how it should be analyzed: age of data,
treatment of non-detects, treatment of pollutants in the source water
and the calculation of toxic-weighted pollutant equivalents.
Age of data. How should EPA take into account changes that may have
occurred in the industry over time and what information would be
appropriate for demonstrating that certain data for certain pollutants
or wastestreams should or should not be used? For
[[Page 34485]]
example, should EPA use a date cutoff for the data used and what
rationale should be used for any such cutoff? EPA encourages commenters
to submit any more recent data (but you should contact EPA first to
make sure the data you submit is usable for the analyses, see above).
Treatment of non-detect values. How should EPA treat non-detects in
effluent data when determining baseline pollutant loadings? What other
information should inform how EPA handles the issue of non-detects,
given that in some cases, analytical methods cannot determine the
actual amount of pollutants in wastewater? Should EPA use a cutoff for
the number or percentage of non-detects in a dataset in order for EPA
to use the dataset for a specific pollutant? For example, there were
more non-detects than detected values for effluent data for sulfides.
Does this dataset provide a sufficient basis, in the absence of any
other information, for estimating pollutant loadings for sulfides?
Treatment of pollutants in the source water. When should EPA adjust
pollutant loadings concentrations to account for contributions from a
facility's source water? Should EPA estimate pollutant loadings for
pollutants for which a certain percentage of the influent concentration
comes from source water? If EPA were to do this, what steps should the
Agency take to ensure the adjustments for source water contribution
definitively link the source water data to the influent and effluent
data?
Calculation of toxic-weighted pollutant equivalents. Is EPA's
calculation of TWPEs appropriate? Do commenters have suggestions,
either generally or relative to specific pollutants, for how this
calculation can be improved?
C. Summary of National Engineering Costs and Pollutant Reductions for
Existing Plants
As described above in Section VIII, EPA evaluated eight regulatory
options comprised of various combinations of the technology options
considered for each wastestream, summarized in Table VIII-1. The Agency
estimated the costs and pollutant loading reductions associated with
steam electric power plants to achieve compliance with each regulatory
option under consideration. This section summarizes the total estimated
compliance costs and pollutant reductions associated with each option
for existing plants (see Tables IX-3 and IX-4). These tables present
the capital cost, annual operating and maintenance costs, one-time
costs, and recurring costs for each regulatory option. Section XI
contains a listing of total annualized costs by regulatory option. All
cost estimates in this section are expressed in terms of pre-tax 2010
dollars. The costs shown in Section XI take into account the timeframe
proposed to meet the limits in the rule.
Information, including plant-specific information, for EPA's
compliance cost and pollutant loading estimates and methodologies is
located in the rulemaking record. Some of the information EPA used to
estimate compliance costs and pollutant loadings was claimed by survey
respondents as CBI. Therefore, this information is not included in the
public docket. However, the public docket contains a number of
documents that set forth EPA's methodology, assumptions and rationale
for developing its cost estimates and pollutant loadings estimates, and
that also present as much data as possible by using aggregation,
summaries, and other techniques to protect CBI. EPA encourages all
interested parties to refer to the record and to provide comments where
appropriate on any aspect of the methodology or the data used to
estimate compliance costs and pollutant loadings associated with this
proposal.
Table IX-3--Cost of Implementation (BAT and PSES)
[In millions of pre-tax 2010 dollars]
----------------------------------------------------------------------------------------------------------------
Number Recurring costs
Regulatory option of Capital Annual One time ---------------------------------------
plants cost O&M cost costs 3-year 5-year 6-year 10-year
----------------------------------------------------------------------------------------------------------------
1.............................. 116 $1,450 $194 $0 $0 $0 $10 ($33)
3a............................. 66 398 177 0 0 0 0 (21)
2.............................. 116 2,499 257 0 0 0 10 (33)
3b............................. 80 998 244 0 0 0 1 (26)
3.............................. 155 2,897 434 0 0 0 10 (54)
4a \a\......................... 200 5,478 689 0.3 1 38 10 (90)
4.............................. 277 8,011 988 0.6 28 65 16 (137)
5.............................. 277 11,755 1,753 0.6 28 65 19 (137)
----------------------------------------------------------------------------------------------------------------
\a\ EPA estimated the costs for Option 4a based on approximated plant-level bottom ash costs for those plants
that have at least one generating unit with a nameplate capacity of 400 MW or less and at least one other
generating unit with a nameplate capacity of greater than 400 MW. For more details on how EPA estimated these
plant-level bottom ash costs, see the memorandum entitled ``Methodologies for Estimating Costs and Pollutant
Removals for Steam Electric ELG Regulatory Option 4a'' (DCN SE03834).
Table IX-4--Estimated Pollutant Loading Reduction (BAT and PSES)
[In million pounds/year]
----------------------------------------------------------------------------------------------------------------
Pollutant removals
-----------------------------------------------------------
Regulatory option Conventional Priority Nonconventional
pollutants \a\ pollutants pollutants \b\
----------------------------------------------------------------------------------------------------------------
1................................................... 2.8 0.5 \c\ (418)
3a.................................................. 16 0.4 468
2................................................... 2.8 0.7 1,155
3b.................................................. 17.1 0.6 914
3................................................... 19 1.1 1,623
4a \d\.............................................. 28 1.4 2,612
4................................................... 35 1.7 3,328
[[Page 34486]]
5................................................... 36 1.7 5,287
----------------------------------------------------------------------------------------------------------------
\a\ The loadings reduction for conventional pollutants includes BOD and TSS. Note that the BOD and TSS removals
are not included in the total pollutant removals stated in Section II (1.63 billion pounds per year for Option
3; 3.34 billion pounds per year for Option 4) to avoid double-counting removals for certain priority and
nonconventional pollutants that would also be measured by these bulk parameters.
\b\ The loadings reduction for nonconventional pollutants excludes TDS and COD to avoid double-counting removals
for certain pollutants that would also be measured by these bulk parameters (e.g., sodium, magnesium).
\c\ Option 1 shows a negative removal for nonconventional pollutants because the mass of several pollutants
(ammonia, chromium, TKN, and BOD) are not quantified at baseline, and because some pollutant discharge
concentrations are higher under Option 1.
EPA estimated the pollutant removals for Option 4a based on
approximated plant-level bottom ash loadings for those plants that have
at least one generating unit with a nameplate capacity of 400 MW or
less and at least one other generating unit with a nameplate capacity
of greater than 400 MW. For more details on how EPA estimated these
plant-level bottom ash loadings, see the memorandum entitled
``Methodologies for Estimating Costs and Pollutant Removals for Steam
Electric ELG Regulatory Option 4a'' (DCN SE03834).
X. Approach To Determine Long-Term Averages, Variability Factors, and
Effluent Limitations and Standards
This section describes the statistical methodology used to
calculate the long-term averages, variability factors, and limitations
for BAT, new source performance standards and pretreatment standards
for existing and new sources. The effluent limitations and standards
are based on long-term average effluent values and variability factors
that account for variation in treatment performance of the model
technology.
The proposed effluent limitations and/or standards, collectively
referred to in the remainder of this section as ``limitations,'' for
pollutants for each technology option, as presented in this notice, are
provided as ``daily maximums'' and ``maximums for monthly averages.''
Definitions provided in 40 CFR 122.2 state that the daily maximum
limitation is the ``highest allowable `daily discharge,''' and the
maximum for monthly average limitation is the ``highest allowable
average of `daily discharges' over a calendar month, calculated as the
sum of all `daily discharges' measured during a calendar month divided
by the number of `daily discharges' measured during that month.'' Daily
discharges are defined to be the ```discharge of a pollutant' measured
during a calendar day or any 24-hour period that reasonably represents
the calendar day for purposes of sampling.'' In this section, the term
``option long-term average'' and ``option variability factor'' are used
to refer to the long-term averages and variability factors for
technology options for an individual wastestream rather than the
regulatory options described in Section VIII.
A. Criteria Used To Select Data as the Basis for the Limitations and
Standards
In developing effluent limitations guidelines and standards for any
industry, EPA qualitatively reviews all the data before selecting data
that represents proper operation of the technology that forms the basis
for the limitations. EPA typically uses four criteria to assess the
data. The first criterion requires that the plants have the model
treatment technology and demonstrate consistently diligent and optimal
operation. Application of this criterion typically eliminates any plant
with treatment other than the model technology. EPA generally
determines whether a plant meets this criterion based upon site visits,
discussions with plant management, and/or comparison to the
characteristics, operation, and performance of treatment systems at
other plants. EPA often contacts plants to determine whether data
submitted were representative of normal operating conditions for the
plant and equipment. As a result of this review, EPA typically excludes
the data in developing the limitations when the plant has not optimized
the performance of its treatment system to the degree that represents
the appropriate level of control (BAT or BADCT).
A second criterion generally requires that the influents and
effluents from the treatment components represent typical wastewater
from the industry, without incompatible wastewater from other sources.
Application of this criterion results in EPA selecting those plants
where the commingled wastewaters did not result in substantial
dilution, unequalized slug loads resulting in frequent upsets and/or
overloads, more concentrated wastewaters, or wastewaters with different
types of pollutants than those generated by the wastestream for which
EPA is proposing effluent limitations.
A third criterion typically ensures that the pollutants are present
in the influent at sufficient concentrations to evaluate treatment
effectiveness. To evaluate whether the data meet this criterion for
inclusion as a basis of the limitations, EPA often uses the long-term
average test (or LTA test) for plants where EPA possesses paired
influent and effluent data (see Section 13 of the Technical Development
Document for details of the LTA test). The test measures the influent
concentrations to ensure a pollutant is present at a sufficient
concentration to evaluate treatment effectiveness. If a dataset for a
pollutant fails the test (i.e., pollutant not present at a treatable
concentration), EPA excludes the data for that pollutant at that plant
when calculating the limitations.
A fourth criterion typically requires that the data are valid and
appropriate for their intended use (e.g., the data must be analyzed
with a sufficiently-sensitive method). Also, EPA does not use data
associated with periods of treatment upsets because these data would
not reflect the performance from well-designed and well-operated
treatment systems. In applying the fourth criterion, EPA may evaluate
the pollutant concentrations, analytical methods and the associated
quality control/quality assurance data, flow values, mass loading,
plant logs, and other available information. As part of this
evaluation, EPA reviews the process or treatment conditions that may
have resulted in extreme values (high and low). As a consequence of
this review, EPA may exclude data associated with certain time periods
or other data outliers that reflect poor performance or
[[Page 34487]]
analytical anomalies by an otherwise well-operated site.
The fourth criterion also is applied in EPA's review of data
corresponding to the initial commissioning period for treatment
systems. Most industries incur commissioning periods during the
adjustment period associated with installing new treatment systems.
During this acclimation and optimization process, the effluent
concentration values tend to be highly variable with occasional extreme
values (high and low). This occurs because the treatment system
typically requires some ``tuning'' as the plant staff and equipment and
chemical vendors work to determine the optimum chemical addition
locations and dosages, vessel hydraulic residence times, internal
treatment system recycle flows (e.g., filter backwash frequency,
duration and flow rate, return flows between treatment system
components), and other operational conditions including clarifier
sludge wasting protocols. It may also take several weeks or months for
treatment system operators to gain expertise on operating the new
treatment system, which also contributes to treatment system
variability during the commissioning period. After this initial
adjustment period, the systems should operate at steady state with
relatively low variability around a long-term average over many years.
Because commissioning periods typically reflect one-time operating
conditions unique to the first time the treatment system begins
operation, EPA generally excludes such data in developing the
limitations.\61\
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\61\ Examples of conditions that are typically unique to the
initial commissioning period include operator unfamiliarity or
inexperience with the system and how to optimize its performance;
wastewater flow rates that differ significantly from engineering
design, altering hydraulic residence times, chemical contact times,
and/or clarifier overflow rates, and potentially causing large
changes in planned chemical dosage rates or the need to substitute
alternative chemical additives; equipment malfunctions; fluctuating
wastewater flow rates or other dynamic conditions (i.e., not steady
state operation); and initial purging of contaminants associated
with installation of the treatment system, such as initial leaching
from coatings, adhesives, and susceptible metal components. These
conditions differ from those associated with the restart of an
already-commissioned treatment system, such as may occur from a
treatment system that has undergone either short or extended
duration shutdown.
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B. Data Used as Basis of the Limitations and Standards
The sections below discuss the data used as the basis for this
proposal, including data selection, the combination of data from
multiple sources within each plant, and the data exclusions made prior
to calculate the limitations.
1. Data Selection for Each Technology Option
This section describes the data selected for use in developing the
limitations for each technology option. This section includes an
abbreviated description of the technology options. See Section VIII for
a more complete discussion of the technology basis for each of the
options considered. For fly ash transport water and FGMC wastewater,
all of the preferred regulatory options propose zero discharge of
pollutants based on dry handling technologies; therefore, no effluent
concentration data were used to set the limitations for these
wastestreams. This is also true for the options that include zero
discharge of pollutants for any set of dischargers for bottom ash.
Except as described in Section VIII, EPA is proposing to establish
limitations for discharges of pollutants in nonchemical metal cleaning
wastes that are equal to the current BPT limitations that apply to
discharges of nonchemical metal cleaning wastes from existing sources
that are direct dischargers. No new effluent concentration data were
used to set the effluent limitations for nonchemical metal cleaning
wastes in this rulemaking, therefore the limitations for this
wastestream are not discussed in this section. See Section VIII for a
more complete discussion of the basis for the proposed limitations.
Under some regulatory options being proposed today, EPA would
establish limitations for certain wastewater discharges that are equal
to the current BPT limitations for those discharges. No new effluent
concentration data would be used to establish BAT/NSPS limitations that
are set equal to BPT, therefore such limitations are not discussed in
this section. See Section VIII for a more complete discussion of the
basis for the proposed regulatory options. For the limitations for
combustion residual leachate (hereafter referred to in this section as
leachate) based on the chemical precipitation technology option, EPA is
proposing to transfer the limitations calculated based on the chemical
precipitation technology option for the FGD wastewater because EPA does
not have the available effluent data for leachate from plants that
employ the chemical precipitation technology. For the limitations based
on the biological treatment technology option for FGD wastewater, EPA
is proposing to transfer the limitations for two pollutants (mercury
and arsenic) calculated based on the chemical precipitation technology
option for the FGD wastewater for the reasons described below. See
Section 13 of the Technical Development Document for a detailed
discussion on the transfer of limitations for leachate and FGD
wastewater.
EPA used specific data sources to derive limitations for pollutants
in FGD and gasification wastewater discharges based on particular
treatment technology. The data sources used to calculate limitations
for each technology option, by wastestream, are described below.
a. FGD Wastewater
As part of the EPA sampling program and additional plant self-
monitoring data EPA obtained during the rulemaking, EPA evaluated the
performance of 10 FGD wastewater treatment systems. For seven of the 10
systems, EPA collected data representing the influent and effluent for
chemical precipitation treatment systems. EPA evaluated these seven
systems and determined that the systems operating the chemical
precipitation system with both hydroxide and sulfide precipitation
achieved better removals of mercury compared to the plants that used
only hydroxide precipitation. Therefore, EPA did not use data from the
three plants that use only hydroxide precipitation. Four of the seven
plants use hydroxide and sulfide precipitation; however, one of the
plants operates a two-stage chemical precipitation system. Because
EPA's basis for the technology option is a one-stage system, EPA did
not use the data from the two-stage system in developing the
limitations.\62\ Therefore, EPA used data from the following three
plants to develop the limitations based on treatment of FGD wastewater
using the chemical precipitation technology option (i.e., one-stage
chemical precipitation system employing both hydroxide and sulfide
precipitation and iron coprecipitation, as well as flow reduction at
plants with large FGD wastewater flow rates, hereafter referred to in
this section as ``chemical precipitation''--see Section VIII above for
a more detailed description):
---------------------------------------------------------------------------
\62\ Based on data EPA has evaluated for the steam electric
industry and other industry sectors, two-stage chemical
precipitation systems generally achieve better pollutant removals
than one-stage systems. Since the technology basis for chemical
precipitation treatment of FGD wastewater in the proposed rule is a
one-stage system and that is the configuration used to estimate
compliance costs, EPA concluded that effluent data for the two-stage
system (Pleasant Prairie) should not be used when calculating
effluent limits for the technology option.
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[[Page 34488]]
Duke Energy's Miami Fort Station (``Miami Fort'');
RRI Energy's Keystone Generating Station (``Keystone'');
and
Allegheny Energy's Hatfield's Ferry Power Station
(``Hatfield's Ferry'').
For the treatment of FGD wastewater using a system that includes
biological treatment as part of the process, EPA evaluated the
treatment systems at three power plants as part of the EPA sampling
program; however, one of the biological treatment systems was not
designed for effective removal of selenium and does not represent the
model technology. The biological treatment technology option is based
on a one-stage chemical precipitation system employing both hydroxide
and sulfide precipitation and iron coprecipitation, as well as flow
reduction at plants with large FGD wastewater flow rates, followed by
anoxic/anaerobic biological treatment designed to remove selenium,
hereafter referred to in this section as ``biological treatment''--see
Section VIII above for a more detailed description. EPA used data from
the following two plants to develop the limitations for the treatment
of FGD wastewater using a one-stage chemical precipitation system
followed by biological treatment:
Duke Energy Carolina's Belews Creek Steam Station
(``Belews Creek''); and
Duke Energy Carolina's Allen Steam Station (``Allen'').
While these two plants operate the biological treatment system
included as the basis for the technology option, neither of these
plants include sulfide precipitation in the upstream chemical
precipitation system and rely only on hydroxide precipitation.
Therefore, the effluent mercury and arsenic concentrations achieved by
these plants do not fully represent the effluent concentrations that
would be achieved by the system used as the design basis for the
technology option. For this reason, EPA is proposing to establish the
mercury and arsenic limitations for the biological treatment technology
option (which includes one-stage chemical precipitation as an initial
treatment stage) based on transferring the limitations that were
calculated for the chemical precipitation treatment technology option.
This is a reasonable approach for establishing mercury and arsenic
limitations for the biological treatment technology option because, in
doing so, EPA would be setting the limitations equal to the performance
that reflects the level of treatment that would be achieved by the
initial treatment stage of the wastewater treatment system.
For the treatment of FGD wastewater using a chemical precipitation
followed by vapor-compression evaporation system hereafter referred to
in this section as ``vapor-compression evaporation'' (which is the
technology serving as the basis for regulatory Option 5, which is not a
preferred option in this proposal), EPA evaluated three systems as part
of the EPA sampling program. One plant operates a system that is
similar to the technology basis for the FGD wastewater limitations in
the proposed rule: A one-stage chemical precipitation system followed
by softening and a vapor-compression evaporation system. EPA used the
data from this plant to develop the limitations based on the vapor-
compression evaporation technology for the treatment of the FGD
wastewater. That plant is Enel's Federico II Power Plant, located in
Brindisi, Italy. EPA used data from a second plant for characterization
purposes and not for limitations development because it only collected
effluent data for one day from the plant. The third system does not
represent the technology serving as the basis for the vapor compression
evaporation option, and thus was not used for the limitations
development. This plant operates a solids removal process prior to the
vapor-compression evaporation system but does not include a full
chemical precipitation system nor a softening step. Furthermore, this
plant also operates a one-stage evaporation system and instead of
employing a second stage of evaporation to crystallize and remove salts
and other pollutants from the concentration brine, mixes the brine with
fly ash and sends it to the landfill for disposal.
b. Gasification Wastewater
For the treatment of gasification wastewater using a vapor-
compression evaporation system, EPA evaluated systems from the
following two plants as part of the EPA sampling program:
Tampa Electric Company's Polk Station (``Polk''); and
Wabash Valley Power Association's Wabash River Station
(``Wabash River'').
Both systems are representative of the system used as the basis for
the technology option and were used in calculating the limitations.
2. Combining Data From Multiple Sources Within a Plant
Typically, if sampling data from a plant were collected over two or
more distinct time periods, EPA analyzes the data from each time period
separately. In previous effluent guidelines rulemakings, where
appropriate, EPA has analyzed the data for each time period as if each
time period represents a different plant since these data can represent
different operating conditions due to changes in management, personnel,
and procedures. On the other hand, when EPA obtains the data (such as
EPA's sampling and plant self-monitoring data) from a plant during the
same time period, EPA combines the data from these sources into a
single dataset for the plant for the statistical analysis.
For this rulemaking, data at most selected plants came from
multiple sources (EPA's sampling, plant sampling as directed by the EPA
through 308 letters, or plant self-monitoring). For some plants, EPA
has data collected from multiple sources during overlapping time
periods. For these plants, EPA combined the multiple sources of data at
each plant into a single dataset for the plant, which provided the
basis for developing the limitations. Other plants had data collected
from multiple sources during non-overlapping time periods. However, in
these instances the time period between the non-overlapping data
collection periods was relatively small (two months). Furthermore, EPA
has no information to indicate that the data represent different
operating conditions. Thus, EPA also combined the multiple sources of
data for each of these plants into a single data set for the plant,
which provided the basis for developing the limitations. Finally, a
couple of plants had data from a single source, and for these plants it
was not necessary to combine data. For a listing of all the data and
their sampling sources for each of the plants, see DCN SE02002,
``Sampling Data Used as the Basis for Effluent Limitations for the
Steam Electric Rulemaking.''
3. Data Exclusions
Following EPA's selection of the model plant(s), EPA applied the
criteria described above in Section A by thoroughly evaluating all
available data for each model plant. EPA identified certain data that
warranted exclusions from the calculations of the limitations because:
(i) The samples were analyzed using an insufficiently-sensitive
analytical method (i.e., use of EPA Method 245.1 instead of Method
1631E for mercury); (ii) the samples were collected during the initial
commissioning period for the treatment system; (iii) or analytical
results were identified as questionable due to quality control issues,
abnormal conditions or treatment upsets, or were analytical anomalies.
See DCN SE01999 for a detailed discussion of the data excluded.
[[Page 34489]]
C. Overview of the Limitations and Standards
The sections below describe EPA's objectives for proposing the
daily maximum and monthly average limitations and the selection of
percentiles for those limitations.
1. Objective
EPA's objective in establishing daily maximum limitations is to
restrict the discharges on a daily basis at a level that is achievable
for a plant that targets its treatment at the long-term average. EPA
acknowledges that variability around the long-term average occurs
during normal operations. This variability means that plants
occasionally may discharge at a level that is higher (or lower) than
the long-term average. To allow for these possibly higher daily
discharges, EPA has established the daily maximum limitation. A plant
that consistently discharges at a level near the daily maximum
limitation would not be operating its treatment to achieve the long-
term average. Targeting treatment to achieve the daily limitation,
rather than the long-term average, may result in values that frequently
exceed the limitations due to routine variability in treated effluent.
EPA's objective in establishing monthly average limitations is to
provide an additional restriction to help ensure that plants target
their average discharges to achieve the long-term average. The monthly
average limitation requires dischargers to provide on-going control, on
a monthly basis, that supplements controls imposed by the daily maximum
limitation. In order to meet the monthly average limitation, a plant
must counterbalance a value near the daily maximum limitation with one
or more values well below the daily maximum limitation. To achieve
compliance, these values must result in a monthly average value at or
below the monthly average limitation.
2. Selection of Percentiles
EPA calculates limitations based upon percentiles that should be
both high enough to accommodate reasonably anticipated variability
within control of the plant, and low enough to reflect a level of
performance consistent with the Clean Water Act requirement that these
effluent limitations be based on the ``best'' available technologies.
The daily maximum limitation is an estimate of the 99th percentile of
the distribution of the daily measurements. The monthly average
limitation is an estimate of the 95th percentile of the distribution of
the monthly averages of the daily measurements. The percentiles for
both types of limitations are estimated using the products of long-term
averages and variability factors. EPA has consistently used the 99th
percentile as the basis of the daily maximum limitation and 95th
percentile as the basis of the monthly average limitation in
establishing limitations for numerous industries and for many years and
numerous courts have upheld EPA's approach.
EPA uses the 99th and 95th percentiles to draw a line at a definite
point in the statistical distributions that would ensure that operators
work to establish and maintain the appropriate level of control. These
percentiles reflect a longstanding Agency policy judgment about where
to draw the line. The development of the limitations takes into account
the reasonable anticipated variability in discharges that may occur at
a well-operated plant. By targeting its treatment at the long-term
average, a well-operated plant should be capable of complying with the
limitations at all times because EPA has incorporated an appropriate
allowance for variability in the limitations.
In conjunction with setting the limitations as described above, EPA
performs an engineering review to verify that the limitations are
reasonable based upon the design and expected operation of the control
technologies and the plant process conditions. As part of the review,
for each plant EPA compared the influent and effluent measurements with
the proposed effluent limitations. See Section F below for details of
these comparisons for each pollutant at each plant, as well as a
discussion of the findings of the engineering review.
D. Calculation of the Limitations and Standards
Effluent limitations and standards are based on a combination of
the long-term average and the appropriate variability factors. In
estimating the limitations for a pollutant, EPA first calculates an
average performance level (the option long-term average discussed
below) that a plant with well-designed and well-operated model
technologies is capable of achieving. This long-term average is
calculated using data from the plant or plants with the model
technologies for the option.
In the second step of developing a limitation for a pollutant, EPA
determines an allowance for the variation (the option variability
factors discussed below) in pollutant concentrations for wastewater
that has been processed through well-designed and well-operated
treatment systems. This allowance for variation incorporates all
components of variability including shipping, sampling, storage, and
analytical variability. This allowance is incorporated into the
limitations through the use of the variability factors, which are
calculated from the data from the plants using the model technologies.
If a plant operates its treatment system to meet the relevant long-term
average, EPA expects the plant will be able to meet the limitations.
Variability factors ensure that normal fluctuations in a plant's
treatment are accounted for in the limitations. By accounting for these
reasonable excursions above the long-term average, EPA's use of
variability factors results in limitations that are generally well
above the long-term averages.
The following sections describe the calculation of the option long-
term averages, option variability factors and limitations, and
adjustments for autocorrelation in calculating the limitations for each
pollutant proposed for regulation.
1. Calculation of Option Long-Term Average
EPA calculated the option long-term average for a pollutant using
two steps. First, EPA calculated the plant-specific long-term average
for each pollutant that had enough distinct detected \63\ values by
fitting a statistical model to the daily effluent concentration values.
In cases when a dataset for a specific pollutant did not have enough
distinct detected values, then the statistical model was not used to
obtain the plant-specific long-term average. In these cases, the plant-
specific long-term average for each pollutant was the arithmetic mean
of the available daily effluent concentration values. Appendix B of the
Technical Development Document contains the required minimum number of
distinct detected observations and an overview of the statistical model
and a description of the procedures EPA used to estimate the plant-
specific long-term average.
---------------------------------------------------------------------------
\63\ For the purpose of discussing the calculation of the long-
term averages, variability factors, and effluent limitations, the
term ``detected'' refers to analytical results measured and reported
above the sample-specific quantitation limit. Thus, values described
in this section as ``non-detected'' refers to values that are below
the method detection limit (MDL) and those measured by the
laboratory as being between the MDL and the quantitation limit (QL).
---------------------------------------------------------------------------
Second, EPA calculated the option long-term average for a pollutant
as the median of the plant-specific long-term averages for that
pollutant. The median is the midpoint of the values when ordered (i.e.,
ranked) from smallest to largest. If there is an odd number of values,
then the value of the mth ordered observation is the median
[[Page 34490]]
(where m=(n+1)/2 and n=number of values). If there is an even number of
values, then the median is the average of the two values in the n/2th
and [(n/2)+1]th positions among the ordered observations.
2. Calculation of Option Variability Factors and Limitations
The following describes the calculations performed to obtain the
option variability factors and limitations. First, EPA calculated the
plant-specific variability factors for each pollutant that had enough
distinct detected values by fitting a statistical model to the daily
effluent concentration values. Each plant-specific daily variability
factor for each pollutant is the estimated 99th percentile of the
distribution of the daily pollutant concentration values divided by the
plant-specific long-term average. Each plant-specific monthly
variability factor for each pollutant is the estimated 95th percentile
of the distribution of the 4-day average pollutant concentration values
divided by the plant-specific long-term average. The calculation of the
monthly variability factor assumes that the monthly averages are based
on the pollutant being monitored weekly (approximately four times each
month). In cases when there were not enough distinct detected values
for a specific pollutant at a plant, then the statistical model was not
used to obtain the plant-specific variability factors. In these cases,
the data for the pollutant at the plant was excluded from the
calculation of the option variability factors. Appendix B of the
Technical Development Document contains the required minimum number of
distinct detected observations and a description of the procedures used
to estimate the plant-specific daily and monthly variability factors.
Second, EPA calculated the option variability factors. The option
daily variability factor for a pollutant was found as the mean of the
plant-specific daily variability factors for that pollutant. Similarly,
the option monthly variability factor was the mean of the plant-
specific monthly variability factors for that pollutant.
Finally, the daily limitation for each pollutant was the product of
the option long-term average and option daily variability factor. The
monthly average limitation for each pollutant was the product of the
option long-term average and option monthly variability factor.
3. Adjustment for Autocorrelation Factors
Effluent concentrations that are collected over time may be
autocorrelated. The data are positively autocorrelated when
measurements taken at specific time intervals, such as one or two days
apart, are similar. For example, positive autocorrelation would occur
if the effluent concentration were relatively high one day and were
likely to remain high on the next and possibly succeeding days. Because
the autocorrelated data may affect the true variability of treatment
performance EPA typically adjusts the variance estimates for the
autocorrelated data, when appropriate. For this rulemaking, whenever
there was sufficient data for a pollutant at a plant to evaluate the
autocorrelation reliably, EPA estimated the autocorrelation and
incorporated it into the calculation of the limitations. For a plant
without enough data to reliably evaluate and obtain a reliable estimate
of the autocorrelation, EPA set the autocorrelation to zero in
calculation of the limitations. EPA did so because there were not
sufficient data to reliably evaluate the autocorrelation, nor did EPA
have a valid correlation estimate available that could be transferred
from a similar technology and wastestream. See DCN SE02001 for details
of the statistical methods and procedures used to determine the
autocorrelation values, as well as a detailed discussion of the minimum
number of observations needed to obtain a reliable estimate of the
autocorrelation. Also, see Section 13 of the TDD.
E. Long-Term Average, Variability Factors, and Limitations for Each
Treatment Option
Due to routine variability in treated effluent, a power plant that
discharges consistently at a level near the values of the daily maximum
limitation or the monthly average limitation may experience frequent
values exceeding the limitations. For this reason, EPA recommends that
power plants design and operate the treatment system to achieve the
option long-term average for the model technology. Thus, a system that
is designed to represent the BAT level of control will be capable of
complying with the limitations. The table below provides the proposed
long-term average, variability factors, and limitations for each of the
FGD, gasification, and leachate treatment technology options. See DCN
SE01999 for details of the calculation of the results presented in the
table below.
Table X-1--Proposed Long-Term Averages, Variability Factors, and Effluent Limitations for Each of the FGD, Gasification, and Leachate Treatment
Technology Options
--------------------------------------------------------------------------------------------------------------------------------------------------------
Daily Monthly
Treatment technology Pollutant Option LTA variability variability Daily Monthly
factor factor limitation \d\ limitation \d\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Chemical Precipitation for FGD............ Arsenic (ug/L).............. 4.483 1.741 1.223 8 6
Mercury (ng/L).............. 75.404 3.209 1.570 242 119
Chemical Precipitation and Biological Arsenic (ug/L)\a\........... 4.483 1.741 1.223 8 6
Treatment for FGD. Mercury (ng/L)\a\........... 75.404 3.209 1.570 242 119
Nitrate-nitrite (mg/L)...... 0.110 1.499 1.157 0.17 0.13
Selenium (ug/L)............. 7.455 2.145 1.321 16 10
Chemical Precipitation and Evaporation for Arsenic (ug/L).............. \b\ 4.0 (\c\) (\c\) \e\ 4 (\f\)
FGD. Mercury (ng/L).............. 17.788 2.192 1.338 39 24
Selenium (ug/L)............. \b\ 5.0 (\c\) (\c\) 5 \e\ (\f\)
TDS (mg/L).................. 14.884 3.341 1.572 50 24
Vapor-Compression Evaporation for Arsenic (ug/L).............. \b\ 4.0 (\c\) (\c\) \e\ 4 (\f\)
Gasification. Mercury (ng/L).............. 1.075 1.632 1.194 1.76 1.29
Selenium (ug/L)............. 146.780 3.083 1.545 453 227
TDS (mg/L).................. 15.209 2.483 1.389 38 22
Chemical Precipitation for Leachate....... Arsenic (ug/L)\a\........... 4.483 1.741 1.223 8 6
Mercury (ng/L)\a\........... 75.404 3.209 1.570 242 119
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Option long-term average, option variability factors, and limitations were transferred from chemical precipitation treatment technology option.
\b\ Long-term average is the arithmetic mean since all observations were non-detected.
[[Page 34491]]
\c\ All observations were non-detected, so the variability factors could not be calculated.
\d\ Limitations less than 1.0 are rounded up to the next highest hundredths decimal place. Limitations greater than 1.0 have been rounded upward to the
next highest integer, except for limitations for mercury based on the vapor-compression evaporation treatment technology option for gasification
wastewater which have been rounded up to the next highest hundredths decimal place.
\e\ Limitation is set equal to the detection limit.
\f\ Monthly average limitation is not established when the daily maximum limitation is based on the detection limit.
F. Engineering Review of Limitations and Standards
In conjunction with the statistical methods, EPA performed an
engineering review to verify that the proposed limitations are
reasonable based upon the design and expected operation of the control
technologies. EPA performed two types of comparisons. First, EPA
compared the limitations to the effluent data used to develop the
limitations. Second, EPA compared the limitations to the influent data.
Sections below summarize the results of these comparisons. For a
detailed discussion of the results, see Section 13 of the Technical
Development Document for Proposed Effluent Limitations Guidelines and
Standards for the Steam Electric Power Generating Point Source Category
(TDD)--EPA 821-R-13.
1. Comparison of Limitations to Effluent Data Used As the Basis for the
Limitations
As part of its data evaluations, EPA compared the limitations to
the effluent values used to calculate the limitations. This type of
comparison helps to evaluate how reasonable the proposed limitations
may be from an engineering perspective. As part of this evaluation, for
each pollutant proposed to be regulated under a technology option, EPA
first compared the daily limitations to the daily effluent values. EPA
then compared the monthly limitations to all the effluent daily values
in a month, and identified those months where at least one value
exceeded the monthly limitations.
After thoroughly evaluating the results of the comparison between
the limitations and the effluent values used to calculate the
limitations for each treatment technology option for FGD and
gasification wastewaters, EPA determined that the statistical
distributional assumptions used to develop the limitations are
appropriate for the data, and thus the proposed limitations for each
technology option are reasonable. (This conclusion is also true for the
leachate limitations based on the chemical precipitation technology
since the leachate limitations were transferred from the FGD wastewater
technology option.) If a plant properly designs and operates its
wastewater treatment system to achieve the option long-term average for
the model technology (rather than targeting performance at the effluent
limits themselves), it will be able to comply with the limitations.
However, EPA notes that some of the daily effluent values for the
BAT plants used to calculate the limitations were found to exceed
either the daily or monthly average effluent limitations. See Section
13.9.1 of the TDD for a detailed discussion of the comparison of the
limitations and the effluent values, including a discussion of those
effluent values that exceed the limitations. EPA solicits comment on
this evaluation and EPA's conclusion that plants with a properly
designed and operating treatment system would be able to comply with
the limitations.
2. Comparison of the Limitations to Influent Data
In addition to comparing the proposed limitations to the data used
to develop the limitations, EPA also compared the value of the proposed
limitations to the influent concentration values. This comparison helps
evaluate whether the proposed limitations are set at a level that
ensures that treatment of the wastewater would be necessary to meet the
limitations and that the influent concentrations were generally well-
controlled by the treatment system. In doing so, EPA confirms that
treatment to remove the regulated pollutants will take place.
For all treatment technology options for both FGD and gasification
wastewater, the minimum, average, and maximum influent concentration
values were much higher than the long-term average and proposed
limitations (see DCN SE01999). Thus, EPA determined that facilities
would need to treat the wastewater to ensure compliance with the
proposed limitations and that the proposed rule would result in
removing the regulated pollutants and other pollutants of concern.
Furthermore, in evaluating influent concentrations, EPA found that
influent concentrations were generally well-controlled by the treatment
system for all plants with model technology. In general, the treatment
systems adequately treated even the extreme influent values, and the
high effluent values did not appear to be the result of high influent
discharges.
EPA expects that facilities will comply with their effluent
limitations at all times. If the exceedance is caused by an upset
condition, the facility would have an affirmative defense to an
enforcement action if the requirements of 40 CFR 122.41(n) are met. If
an exceedance is caused by a design or operational deficiency, then EPA
has determined that the facility's performance does not represent the
appropriate level of control. For these proposed limitations, EPA has
determined that such exceedances can be controlled by diligent process
and wastewater treatment system operational practices such as frequent
inspection and repair of equipment, use of back-up systems, and
operator training and performance evaluations. Additionally, some
facilities may need to upgrade or replace existing treatment systems to
ensure that the treatment system is designed to achieve performance to
target the effluent concentrations at the option long-term average.
This is consistent with EPA's costing approach for the ELG technology
options and its engineering judgment developed over years of evaluating
wastewater treatment processes for power plants and other industrial
sectors. EPA recognizes that, as a result of the proposed rule, some
dischargers, including those that are operating technologies
representing the ``best available'' technology, may need to improve
their treatment systems, process controls, and/or treatment system
operations in order to consistently meet the effluent limitations. EPA
believes that this is consistent with the Clean Water Act, which
requires that discharge limitations reflect the best available
technology economically achievable or the best available demonstrated
control technology.
XI. Economic Impact and Social Cost Analysis
A. Introduction
EPA assessed the social costs and the projected economic impacts of
the eight regulatory options described in this proposal (see Section
VIII for a description of the options). This section provides an
overview of the methodology EPA used to assess the social costs (or
costs from the viewpoint of society rather than the regulated entity)
and the economic impacts of the proposed ELGs and summarizes the
results of these analyses. The Regulatory
[[Page 34492]]
Impact Analysis for Proposed Effluent Limitations Guidelines and
Standards for the Steam Electric Power Generating Point Source Category
(RIA)--EPA 821-R-13-005 and Benefits and Cost Analysis for the Proposed
Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category (BCA)--EPA 821-R-13-004 reports
available in the record for the rulemaking provide more details on
these analyses, including discussion of uncertainties and limitations.
EPA estimated the costs to electric power producers--which include
steam electric plants owned by investor-owned utilities,
municipalities, states, federal authorities, cooperatives, and
nonutilities, whose primary business is electric power generation or
related electric power services--of complying with the proposed ELGs.
As described in Section VI of this preamble, EPA estimated that 1,079
power plants operated at least one steam electric generating unit
subject to the ELGs in 2009. EPA evaluated the costs and associated
impacts of this proposal on these existing plants, and on new units
that may be subject to the proposed revisions to the ELGs in the
future. Plants that EPA estimates would incur compliance costs as a
result of the proposed revisions to the ELGs are a subset of the 1,079
steam electric power plants.\64\
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\64\ As discussed in Section VIII, EPA is proposing different
effluent limits for existing oil-fired generating units and units
with a capacity of 50 MW or less. Because this proposed rule would
set BAT equal to BPT limits, EPA accordingly did not estimate
incremental costs for these units as a result of this proposed rule.
Many plants are comprised of multiple units, and as such, there may
be costs associated with some but not all units at a plant. The
plants may incur costs for other, larger units, however, if any such
units are also present; EPA's analysis includes costs for these
larger units.
---------------------------------------------------------------------------
B. Annualized Compliance Costs
EPA's analyses of costs and economic impacts use the plant-level
costs described in Section IX of this preamble. As described in that
section, EPA developed plant-specific compliance costs for plants that
generate a wastestream for which EPA evaluated new limitations and
standards. Plant-specific compliance costs were developed for those
plants for which EPA obtained detailed technical data through the
industry survey. These costs consist of two principal components:
initial planning and capital costs; and recurring operating and
maintenance costs, which occur annually or according to a specified
frequency (e.g., every 3 years, 5 years, 6 years, or 10 years). EPA
applied survey weights to obtain costs for all 1,079 steam electric
plants. Since all plants incurring non-zero costs have a sample weight
of 1, the sum of costs for the surveyed plants also represents the
total costs for the entire universe of 1,079 plants.
EPA restated compliance costs, accounting for the specific years in
which each plant is assumed to undertake compliance-related activities
and in 2010 dollars, using Construction Cost Index (CCI) from McGraw
Hill Construction, the Employment Cost Index (ECI) published by the
Bureau of Labor Statistics, and the Gross Domestic Product (GDP)
deflator index published by the U.S. Bureau of Economic Analysis (BEA).
EPA used 2010 dollars based on data available at the time the analysis
was developed. As a result, all dollar values reported in this analysis
are in constant 2010 dollars.
EPA annualized the stream of future costs using 7 percent. The rate
of 7 percent is used in the cost impact analysis as an estimate of the
opportunity cost of capital.
EPA annualized one-time costs and costs recurring on other than an
annual basis over a specific useful life, implementation, and/or event
recurrence period, using a rate of 7 percent. For capital costs and
initial one-time costs, EPA used 20 years. For O&M costs incurred at
intervals greater than one year, EPA used the interval as the
annualization period (i.e., 3 years, 5 years, 6 years, 10 years). EPA
added annualized capital, initial one-time costs, and the non-annual
portion of O&M costs to annual O&M costs to derive total annualized
compliance costs, where all costs are expressed on an equivalent
constantly recurring annual cost basis.
EPA uses pre- and/or after-tax compliance costs in different
analyses, depending on the concept appropriate to each analysis (e.g.,
cost-to-revenue screening-level analyses discussed in Section XI.D are
conducted using after-tax compliance costs, whereas social costs
discussed in Section XI.C are calculated using pre-tax costs). For the
assessment of compliance costs, EPA considered costs on both a pre-tax
and after-tax basis. Pre-tax costs provide insight on the total
expenditure as incurred. After-tax costs are a more meaningful measure
of compliance impact on privately owned for-profit plants, and
incorporate approximate capital depreciation and other relevant tax
treatments in the analysis. EPA calculated the after-tax value of
compliance costs by applying combined federal and State tax rates to
the pre-tax cost values for privately owned for-profit plants. For this
adjustment, EPA used State corporate rates from the Federation of Tax
Administrators (http://www.taxadmin.org/) combined with federal
corporate tax rate schedules from the Department of the Treasury,
Internal Revenue Service.
Table XI-1 presents the total annualized compliance costs of the
regulatory options on existing plants, estimated on a pre-tax and
after-tax base. The table lists the eight options in order of
increasing total annualized compliance costs. As shown in the table,
after-tax annualized compliance costs range between $108.4 million and
$1.55 billion for Options 3a and 5, respectively, with the preferred
BAT and PSES options estimated to have annualized industry-wide after-
tax costs of $108.4 million, $182.2 million, $389.0 million, $635.7
million (after-tax), respectively for Options3a, 3b, 3, and 4a. The
costs shown in Table XI-1 do not reflect the compliance costs for new
sources.
Table XI-1--Total Annualized Compliance Costs
[In millions, 2010$]
------------------------------------------------------------------------
7% Discount rate Pre-tax After-tax
------------------------------------------------------------------------
Option 3a......................................... $168.1 $108.4
Option 3b......................................... 264.6 182.2
Option 1.......................................... 265.9 190.6
Option 2.......................................... 393.3 280.6
Option 3.......................................... 561.3 389.0
Option 4a......................................... 947.8 635.7
Option 4.......................................... 1,373.2 916.9
Option 5.......................................... 2,277.3 1,547.9
------------------------------------------------------------------------
The compliance costs above account for unit retirements,
repowerings and conversions that have been announced by companies and
are scheduled to occur by 2014, based on information obtained by EPA as
of August 2012. But they do not reflect additional planned unit
retirements, repowerings, and conversions that have been announced
since August 2012, nor do they reflect announced retirements,
repowerings, and conversions that are scheduled to occur by 2022. (See
DCN SE02033, ``Changes to Industry Profile for Steam Electric
Generating Units Updates''). EPA estimates that accounting for these
changes would reduce total annualized compliance costs. For example,
EPA estimated that total pre-tax annualized compliance costs for Option
3 would go from $561.3 million to $532.8 million (5 percent reduction),
whereas costs for Option 4 would go from $1,373.2 million to $1,252.9
million (9 percent reduction).
[[Page 34493]]
C. Social Costs
Social costs are the costs of the rule from the viewpoint of
society as a whole, rather than regulated facilities. In calculating
social costs, EPA tabulated the pre-tax costs in the year when they are
incurred. EPA assumed that all plants subject to the proposed
regulation that would need to upgrade their systems would install
control technologies over a five-year period beginning in 2017. This
accounts for the time plants would have to implement control
technologies, as described in Section XVI. For the purpose of the
economic analyses, EPA assumed that plants would implement control
technologies 3 years after the renewal of their individual NPDES
permit, following the promulgation year, with NPDES permits assumed to
be renewed on time, following a 5-year cycle.\65\
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\65\ These assumed technology installation years do not
necessarily correspond to the actual years in which individual
facilities would be required to meet the effluent limits or
standards as specified in their permit, but is a reasonable
distribution of installation years for the aggregate set of steam
electric plants incurring compliance costs. These assumptions
reflect the approximate years in which technology installation would
reasonably be expected to occur, assuming that expiring permits are
renewed exactly on the 5-year mark. Note that EPA also analyzed the
effects of other technology installation periods. The results of
these analyses are detailed in Appendix B of the RIA report.
---------------------------------------------------------------------------
EPA performed the social cost analysis over a 24-year analysis
period, which combines the length of the period during which plants are
expected to install the control technologies (five-year period
beginning in 2017) and the useful life of the longest-lived compliance
technology installed at any facility (20 years). Under this framework,
the last year for which costs (and benefits) were tallied in the
analysis is 2040. EPA calculated social cost of the eight regulatory
options for existing steam electric power plants using a 3 percent
discount rate. EPA also calculated social costs using an alternative
discount rate of 7 percent.\66\ For the analysis of social costs, EPA
discounted all costs to the beginning of 2014, which is the expected
promulgation year for the proposed rule.
---------------------------------------------------------------------------
\66\ These discount rate values follow guidance from the Office
of Management and Budget (OMB) regulatory analysis guidance
document, Circular A-4 (OMB, 2003).
---------------------------------------------------------------------------
As described in Section XVII.B, EPA does not believe the proposed
rule would lead to additional costs to permitting authorities.
Consequently, the only category of costs necessary to calculate social
costs are compliance costs; social costs differ from pre-tax compliance
costs due to timing of costs and discounting using a societal discount
rate.
Table XI-2 presents the total annualized social cost of the
regulatory options on existing plants, calculated using 3 percent and 7
percent discount rates. The table lists the eight options in order of
increasing total social costs calculated using a 3 percent discount
rate.
Table XI-2--Total Annualized Social Costs
[In millions, 2010$]
------------------------------------------------------------------------
3% Discount 7% Discount
Regulatory option rate rate
------------------------------------------------------------------------
Option 3a................................... $185.2 $164.5
Option 1.................................... 268.3 259.2
Option 3b................................... 281.4 257.2
Option 2.................................... 386.8 380.8
Option 3.................................... 572.0 545.3
Option 4a................................... 954.1 914.7
Option 4.................................... 1,381.2 1,323.2
Option 5.................................... 2,328.8 2,209.4
------------------------------------------------------------------------
At 3 percent discount rate, total annualized social costs for
existing plants vary from $185.2 million under Option 3a to $2.3
billion under Option 5, with the preferred BAT and PSES options having
total annualized social costs of $185.2 million, $281.4 million, $572.0
million, and $954.1 million, respectively for Options 3a, 3b, 3 and 4a.
The values presented in Table XI-2 for the 7 percent discount rate are
slightly lower than the comparable values (pre-tax) presented in Table
XI-1 due to the timing of compliance expenditures (e.g., $545.3 million
versus $561.3 million, for Option 3).
These social costs do not reflect anticipated unit retirements and
conversions anticipated through 2024. As noted in the previous Section,
EPA anticipates that these changes would reduce total compliance costs
incurred by the Steam Electric power industry, and therefore reduce the
social costs of this action.
D. Economic Impacts
EPA assessed the economic impacts of the regulatory options in two
ways: (1) A screening-level assessment of the impact of compliance
costs on existing plants and the entities that own those plants, based
on comparison of compliance costs to plant and entity revenue; and (2)
an assessment of the impact of the proposed regulatory options for both
existing and new plants within the context of the broader electricity
market, which includes an assessment of incremental plant closures
attributable to the proposed ELGs. EPA used the results of the
screening-level assessment to inform the selection of regulatory
options to be analyzed using the second approach.
The following sections summarize the methods and findings for these
analyses.
1. Screening-Level Assessment of Impacts on Existing Plants and Parent
Entities Incurring Compliance Costs Associated With This Proposed Rule
EPA conducted a screening-level analysis of the rule's potential
impact to existing steam electric plants and parent entities based on
cost-to-revenue ratios. For each of the two levels of analysis (plant
and parent entity), the Agency assumed, for analytic convenience and as
a worst-case scenario, that none of the compliance costs would be
passed onto consumers through electricity rate increases and would
instead be absorbed by complying plants and their parent entities. In
performing these and other impact analyses, EPA used the survey weights
to extrapolate impacts assessed initially for a sample of plants to all
1,079 steam electric plants and to their respective owning parent
entities.
a. Cost-to-Revenue Analysis for Plants Incurring Compliance Costs
Associated with this Proposed Rule
EPA calculated the annualized after-tax compliance costs of the
regulatory options as a percent of baseline annual revenues.\67\
Revenue estimates used in this analysis were developed using Energy
Information Administration (EIA) data. (See Chapter 4 of the RIA report
for a more detailed discussion of the methodology used for the plant-
level cost-to-revenue analysis).\68\
---------------------------------------------------------------------------
\67\ For private, tax-paying entities, after-tax costs are a
more relevant measure of potential cost burden than pre-tax costs.
For non tax-paying entities (e.g., State government and municipality
owners of affected plants), the estimated costs used in this
calculation include no adjustment for taxes.
\68\ To develop the average of year-by-year revenue values over
the data years, EPA set aside from the averaging calculation,
revenue values for years that are substantially lower than the
otherwise ``steady state average''--e.g., because of a generating
unit being out of service for an extended period.
---------------------------------------------------------------------------
Table XI-3 summarizes the screening-level plant-level cost-to-
revenue analysis results for the eight main regulatory options. EPA
estimates that the vast majority of plants subject to the proposed ELGs
will incur annualized costs amounting to less than 1 percent of revenue
for all eight regulatory options (887 to 1,051 plants, or 82 to 97
percent of the total 1,079 steam electric plants). A significant share
of these plants incur no compliance costs. For the preferred BAT and
PSES options (Options 3a, 3b, 3 and 4a), 92 percent to 97 percent of
steam electric plants have estimated costs that are less than 1 percent
of revenue. The number of plants with ratios between 1 percent and 3
percent, and above 3 percent,
[[Page 34494]]
generally rises when moving from Option 3a to Option 5. For the
preferred BAT and PSES options (Options 3a, 3b, 3 and 4a), two to six
percent of plants have cost-to-revenue ratios between 1 and 3 percent
and less than one percent to two percent have ratios above 3 percent.
Table XI-3--Plant-Level Cost-to-Revenue Analysis Results by Regulatory Option a
----------------------------------------------------------------------------------------------------------------
Number of plants with cost-to-revenue ratio of
Option No data on ---------------------------------------------------
revenue \b\ 0% 0-1% 1-3% >3%
----------------------------------------------------------------------------------------------------------------
Option 3a...................................... 5 1,008 43 22 1
Option 3b...................................... 5 994 54 24 2
Option 1....................................... 5 959 93 17 5
Option 2....................................... 5 959 86 18 11
Option 3....................................... 5 920 102 38 14
Option 4a...................................... 5 875 114 65 20
Option 4....................................... 5 798 111 117 48
Option 5....................................... 5 798 89 115 72
----------------------------------------------------------------------------------------------------------------
\a\ This analysis makes a counterfactual, conservative assumption of zero cost pass-through. Plant counts are
weighted estimates.
\b\ EIA does not report necessary data to estimate revenue for 5 plants.
b. Parent Entity-Level Cost-to-Revenue Analysis
EPA also assessed the economic impact of the eight regulatory
options at the parent entity-level. The screening-level cost-to-revenue
analysis at the parent entity level provides insight on the impact of
compliance requirements on those entities that own more than one plant
incurring compliance costs associated with this proposed rule. For this
analysis, EPA identified the domestic parent entity of each plant and
obtained the entity's revenue from the industry survey or from publicly
available data sources. In this analysis, the domestic parent entity
associated with any given plant is defined as that entity that has the
largest ownership share in the plant.
For each parent entity, EPA compared the total annualized after-tax
compliance costs, as of 2014, and the identified parent entity's total
revenue (see Chapter 4 of the RIA report for details). The total
parent-level annualized after-tax compliance costs represent total
costs for all steam electric plants in which the entity is the majority
owner.
Compliance costs for the regulatory options were developed based on
surveyed plants (see Section XI.D.1.a). For the parent entity-level
analysis, EPA considered two approximate bounding cases to analyze the
owners of all 1,079 steam electric plants, based on the survey weights
developed from the industry survey. These cases, which are described in
more detail in Chapter 4 of the RIA, provide a range of estimates for
the number of entities incurring compliance costs and the costs
incurred by any entity owning a steam electric plant.
Table XI-4 summarizes the results of the entity-level analysis for
the two analytic cases and the eight regulatory options.
Table XI-4--Parent Entity-Level After-Tax Annual Compliance Costs as a Percentage of Revenue a
--------------------------------------------------------------------------------------------------------------------------------------------------------
Not analyzed due Number and percentage with after tax annual compliance costs/annual
to lack of revenue of:
Total revenue ---------------------------------------------------------------------------
Option number of information 0% 0-1% 1-3% 3% or Greater
entities ----------------------------------------------------------------------------------------------
% % % % %
--------------------------------------------------------------------------------------------------------------------------------------------------------
Case 1: Lower-bound estimate of number of entities owning steam electric plants; upper bound estimate of total compliance costs that an entity may incur
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3a..................................... 243 14 6 205 84 22 9 2 1 0 0
Option 3b..................................... 243 14 6 201 83 26 11 2 1 0 0
Option 1...................................... 243 14 6 173 71 51 21 1 <1 4 2
Option 2...................................... 243 14 6 173 71 46 19 6 2 4 2
Option 3...................................... 243 14 6 168 69 49 20 7 3 5 2
Option 4a..................................... 243 14 6 157 65 55 23 11 5 6 2
Option 4...................................... 243 14 6 137 56 64 26 21 9 7 3
Option 5...................................... 243 14 6 137 56 57 23 20 8 15 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Case 2: Upper-bound estimate of number of entities owning steam electric plants; lower bound estimate of total compliance costs that an entity may incur
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3a..................................... 507 30 6 453 89 22 4 2 <1 0 0
Option 3b..................................... 507 30 6 449 89 26 5 2 <1 0 0
Option 1...................................... 507 30 6 421 83 51 10 1 <1 4 1
Option 2...................................... 507 30 6 421 83 46 9 6 1 4 1
Option 3...................................... 507 30 6 416 82 49 10 7 1 5 1
Option 4a..................................... 507 30 6 405 80 55 11 11 2 6 1
Option 4...................................... 507 30 6 385 76 64 13 21 4 7 1
Option 5...................................... 507 30 6 385 76 57 11 20 4 15 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
equals the number of entities.
[[Page 34495]]
\a\ This analysis makes a counterfactual, conservative assumption of zero cost pass-through.
The cost-to-revenue ratios provide screening-level indicators of
potential economic impacts. Entities incurring costs below 1 percent of
revenue are unlikely to face economic impacts, while entities with
costs between 1 percent and 3 percent of revenue have a higher chance
of facing economic impacts, and entities incurring costs above 3
percent of revenue have a still higher probability of economic impacts.
As presented in Table XI-4, EPA estimated that the number of entities
owning steam electric plants ranges from 243 (lower bound estimate) to
507 (upper bound estimate), depending on the assumed ownership
structure of plants not surveyed. Under the lower-bound case, EPA
estimates that the vast majority of parent entities will incur
annualized costs of less than 1 percent of revenues under all eight
analyzed regulatory Options (the shares are 93, 93, 89, and 87 percent
under Options 3a, 3 and 4a, respectively). These observations also hold
true under the upper bound case; an estimated 94, 94, 92, and 91
percent of parent entities incur annualized costs of less than 1
percent of revenue, for Options 3a, 3b, 3 and 4a, respectively.
Overall, this screening-level analysis shows that the entity-level
compliance costs are low in comparison to the entity-level revenues;
very few entities are likely to face economic impacts at any level for
any of the four preferred BAT and PSES options (Options 3a, 3b, 3 and
4a).
2. Assessment of the Impacts in the Context of Electricity Markets
In analyzing the impacts of regulatory actions affecting the
electric power sector, EPA has used the Integrated Planning Model
(IPM), a comprehensive electricity market optimization model that can
evaluate such impacts within the context of regional and national
electricity markets. The model is designed to evaluate the effects of
changes in production costs at the level of the individual generating
unit, on the total cost of electricity supply, subject to specified
demand and emissions constraints. To assess facility and market-level
effects of these proposed ELGs, EPA used an updated version of this
same analytic system: Integrated Planning Model Version 4.10 MATS (IPM
V4.10).
Use of a comprehensive, market analysis system is important in
assessing the potential impact of the regulatory options because of the
interdependence of electricity generating units in supplying power to
the electric transmission grid. Increases in electricity production
costs at some plants can have a range of broader market impacts
affecting other plants, including the likelihood that various plants
are dispatched, on average.
IPM V4.10 provides outputs for the North American Electric
Reliability Corporation (NERC) regions that lie within the continental
United States. IPM V4.10 does not analyze electric power operations in
Alaska and Hawaii because these states' electric power operations are
not connected to the continental U.S. power grid. However, none of the
steam electric plants that are estimated to incur compliance costs
associated with this proposal are located in these two regions.
IPM V4.10 is based on an inventory of U.S. utility- and non-
utility-owned boilers and generators that provide power to the
integrated electric transmission grid, as recorded in EIA 860 (2006)
and EIA 767 (2005) databases.\69\ The IPM baseline universe of plants
includes nearly all of the steam electric plants that could be subject
to the proposed ELGs and are estimated to incur compliance costs.\70\
IPM Version 4.10 embeds a baseline energy demand forecast that is
derived from DOE's Annual Energy Outlook 2010 (AEO2010). IPM V4.10 also
incorporates in its analytic baseline the expected compliance response
to existing regulatory requirements for the following promulgated air
regulations affecting the power sector: the final Mercury and Air
Toxics Standards (MATS) rule; the final Cross-State Air Pollution Rule
(CSAPR) \71\; regulatory SO2 emission rates arising from
State Implementation Plans (SIP); Title IV of the Clean Air Act
Amendments; NOX SIP Call trading program; Clean Air Act
Reasonable Available Control Technology requirements and Title IV unit
specific rate limits for NOX; the Regional Greenhouse Gas
Initiative; Renewable Portfolio Standards; New Source Review
Settlements; and several state-level regulations affecting emissions of
SO2, NOX, and mercury that are already in place
or expected to come into force by 2017.
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\69\ In some instances, plant information has been updated to
reflect known material changes in a plant's generating capacity
since 2006.
\70\ The IPM plant universe excludes two steam electric plants
estimated to incur compliance costs under the proposed ELG scenarios
EPA analyzed in IPM. See Chapter 5 of the RIA report for more
details.
\71\ EPA's Cross-State Air Pollution Rule (CSAPR) was
promulgated to replace EPA's Clean Air Interstate Rule (CAIR), which
had been remanded to EPA in 2008. However, on December 30, 2011, the
U.S. Court of Appeals for the D.C. Circuit stayed CSAPR pending
judicial review and left CAIR in place. On August 21, 2012 the Court
issued an opinion vacating CSAPR and again leaving CAIR in place
pending development of a valid replacement. On March 29, 2013, the
United States filed a petition asking the Supreme Court to review
the D.C. Circuit's opinion. Nevertheless, as explained above, CAIR
remains in effect at this time. In light of the continuing
uncertainty on CAIR and CSAPR, EPA does not believe it would be
appropriate or possible at this time to adjust emission projections
on the basis of speculative alternative emission reduction
requirements in 2020. EPA expects that the decision vacating CSAPR
and leaving CAIR in place has a minimal effect on the results of the
analysis conducted in support of the proposed ELGs.
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In contrast to the screening-level analyses, which are static
analyses and do not account for interdependence of electric generating
units in supplying power to the electric transmission grid, IPM
accounts for potential changes in the generation profile of steam
electric and other units and consequent changes in market-level
generation costs, as the electric power market responds to higher
generation costs for steam electric units due to the proposed ELGs. IPM
is also dynamic in that it is capable of using forecasts of future
conditions to make decisions for the present. Additionally, in contrast
to the screening-level analyses in which EPA assumed no pass through of
compliance costs, IPM depicts production activity in wholesale
electricity markets where some recovery of compliance costs through
increased electricity prices is possible but not guaranteed.
In performing analyses based on IPM V4.10, EPA used as its
baseline--i.e., reflecting the world without this proposed regulation--
a projection of electricity markets and facility operations over the
period from the expected promulgation year, 2014, through 2030. As
discussed above, this baseline accounts for compliance with the
recently promulgated federal air rules.
As discussed in greater detail in Appendix C of the RIA, IPM
generates least-cost resource dispatch decisions based on user-
specified constraints such as environmental, demand, and other
operational constraints. In analyzing the proposed ELGs, EPA specified
additional fixed and variable costs that are expected to be incurred by
specific steam electric plants and generating units to comply with the
proposed ELGs. EPA then ran IPM including these additional costs to
determine the dispatch of electricity generating units that would meet
projected demand at
[[Page 34496]]
the lowest costs, subject to the same constraints as those present in
the analysis baseline. The least-cost dispatch solution for meeting
electricity supply may change as the result of the changes in fixed and
variable costs at the level of the individual plant and generating
unit, which EPA estimates would occur as a result of the proposed ELGs.
These estimated changes in plant- and unit-specific production levels
and costs--and, in turn, changes in total electric power sector costs
and production profile--are key data elements in evaluating the
expected national and regional effects of the proposed ELGs.
EPA used the screening-level analyses described above to inform the
selection of regulatory options to be analyzed using IPM. In allocating
resources to analytical effort, EPA chose to run IPM in a phased
approach, starting with Option 3 and then Option 4, with the notion to
proceed if additional model runs were warranted.
EPA first analyzed a scenario developed based on Option 3 but where
the total compliance costs and the set of existing plants that are
assigned costs varied slightly from those in the Option 3 discussed in
other parts of this preamble.\72\ Thus, the Option 3 scenario analyzed
using IPM and discussed below did not include small changes to the
timing of some O&M costs and to the set of plants assigned compliance
costs for this option. Because of these changes and the need to protect
data claimed as CBI by plant owners, total compliance costs for Option
3 as analyzed in IPM are approximately 10 percent lower than for the
proposed Option 3 discussed in the rest of this document. EPA also
analyzed a scenario in IPM that corresponds to BAT and PSES Option 4
discussed elsewhere in this notice.\73\ Both scenarios analyzed in IPM
included NSPS and PSNS compliance costs for new coal generation, based
on the preferred Option 4 for new sources.
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\72\ The costs as analyzed in IPM differ slightly from those
used in the non-IPM analyses. For more details on these differences,
see Chapter 5 of the RIA report. Note that the scenario assigns
compliance costs for existing plants based on Option 3, and
compliance costs for new capacity projected in IPM based on Option
4.
\73\ Compliance costs differ only slightly (1 percent lower)
from costs used in other analyses, primarily to avoid disclosing
CBI. There are no differences in the set of plants estimated to
incur compliance costs or in the timing of the costs. For more
details, see Chapter 5 of the RIA report.
---------------------------------------------------------------------------
The two scenarios analyzed in IPM provide insight on the market
impacts of the regulatory options EPA considered for this proposal.
Options 3 and 4 as analyzed in IPM are similar enough to these proposed
Options 3 and 4 to provide valuable insight on the likely impacts of
the proposed ELGs. Options 3a, 1, 2, and 3b are less stringent than
either of the two other options analyzed in IPM; as discussed further
below, the relatively small impacts observed when analyzing the Option
3 scenario suggest that the impacts of Options 3a, 1, 2 and 3b would be
less than Option 3. EPA did not analyze Option 4a due to time and
resource constraints, but expects that this option could have impacts
between those of Options 3 and 4. EPA did not analyze Option 5 based on
screening-level analysis results, which showed that compliance costs
could result in financial stress to some entities owning steam electric
plants. As shown in Section XI.D.1, under Option 5, about three times
as many entities owning steam electric plants would incur costs that
exceed 3 percent of revenue than under Options 3 (15 versus 5
entities). Twice as many entities owning steam electric power plants
are estimated to incur costs that exceed 3 percent of revenue under
Option 5, when compared to Option 4 (15 versus 7 entities). As
discussed in Section XVII.C, the potential cost impacts to small
entities are also greater under Option 5 than under Options 3 and 4.
The IPM V4.10 runs provide analysis results for selected run-years:
2020 and 2030. These analysis years, each of which represents multiple
years, take into account the expected promulgation year for these
proposed ELGs (2014) and the years in which all plants would be
expected to install compliance technology (five-year period beginning
in 2017). In the following sections, EPA reports results for the run-
year 2030, which represents years 2025-2034, by which time all plants
subject to this rulemaking will meet the revised guidelines and
standards and all compliance costs will be reflected in production
costs (i.e., steady state of post-compliance operations). EPA
considered impact metrics of interest at three levels of aggregation:
(1) Impact on national and regional electricity markets (i.e., all
electric power generation, including steam and non-steam plants), (2)
impact on steam electric power generating plants as a group (i.e., the
1,079 plants subject to the proposed ELGs, not all of which are
projected to incur compliance costs), and (3) impact on individual
steam electric plants incurring compliance costs.
All results presented below are representative of modeled market
conditions in the years 2025-2034. While costs are in 2010 dollars,
they are reflective of costs in the modeled years and are not
discounted to the start of EPA's analysis period of 2014.\74\
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\74\ In contrast, the social cost estimated in Section XI.C
reflects the discounted value of compliance costs over the entire
24-year period of analysis, as of 2014. Additionally, screening-
level analyses presented in earlier sections are static analyses and
do not account for interdependence of electric generating units in
supplying power to the electric transmission grid. In contrast, IPM
accounts for potential changes in generation profile of steam
electric and other units and consequent changes in market-level
generation costs, as the electric power market responds to higher
generation costs for steam electric units due to the proposed ELG.
---------------------------------------------------------------------------
a. Impact on National and Regional Electricity Markets
For the assessment of market level electricity impacts, EPA
considered five output metrics from IPM V4.10: (1) Incremental early
retirements and capacity closures, calculated as the difference between
capacity under the regulatory options and capacity under the baseline,
which includes both full plant closures and partial plant closures
(i.e., unit closures) in aggregate capacity terms; (2) incremental
capacity closures as a percentage of baseline capacity; (3) post-
compliance changes in variable production costs per MWh, calculated as
the sum of total fuel and variable O&M costs divided by net generation;
(4) changes in annual costs (fuel, variable O&M, fixed O&M, and
capital); and (5) post-compliance changes in energy price, where
electricity prices are defined as the wholesale prices received by
plants for the sale of electricity they generate.
Table XI-5 presents results for the two market model analysis
scenarios. The table provides the baseline capacity and the values of
each of the five metrics above, with national totals and detail at
level of regional electricity markets defined on the basis of the eight
NERC regions defined in IPM.
Additional results are presented in Chapter 5 of the RIA report.
Chapter 5 also presents a more detailed interpretation of the results
of the market-level analysis.
[[Page 34497]]
Table XI-5--Impact of Market Model Analysis Options on National and Regional Markets at the Year 2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
Incremental early retirements/ Change in Change in Change in
closures \a\ variable annual costs electricity
NERC region Baseline ------------------------------------ production cost (million 2010$ price (2010$/MWh
capacity (GW) % of Baseline (2010$/MWh or % or % of or % of
Capacity (GW) closures of baseline) baseline) baseline)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3:
ERCOT................................... 98 0 0.0 $0.11 0.3% $72 0.4% $0.21 0.3%
FRCC.................................... 68 0 0.0 0.14 0.3 49 0.3 0.23 0.3
MRO..................................... 76 0 0.0 0.02 0.1 53 0.4 0.03 0.1
NPCC.................................... 73 0 0.0 0.06 0.2 15 0.1 0.19 0.3
RFC..................................... 237 0 0.0 0.12 0.5 276 0.5 0.19 0.3
SERC.................................... 274 0 0.0 0.17 0.6 322 0.6 0.24 0.4
SPP..................................... 59 0 -0.7 0.08 0.3 35 0.3 0.17 0.3
WECC.................................... 220 0 0.0 0.05 0.2 50 0.1 0.15 0.2
-----------------------------------------------------------------------------------------------------------
Total............................... 1,106 0 0.0 0.11 0.4 872 0.4 N/A
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 4:
ERCOT................................... 98 0 0.0 0.14 0.4 85 0.5 0.07 0.1
FRCC.................................... 68 0 0.0 0.15 0.1 33 0.2 0.09 0.1
MRO..................................... 74 0 0.0 0.11 0.5 134 1.0 -0.05 -0.1
NPCC.................................... 73 0 0.6 0.03 0.1 32 0.2 0.04 0.1
RFC..................................... 237 1 0.3 0.29 1.1 804 1.5 0.15 0.2
SERC.................................... 274 0 0.0 0.28 1.0 662 1.2 0.19 0.3
SPP..................................... 60 0 -0.6 0.15 0.5 72 0.7 0.09 0.2
WECC.................................... 220 0 0.0 0.03 0.1 52 0.1 0.04 0.1
-----------------------------------------------------------------------------------------------------------
Total............................... 1,106 0 0.0 0.18 0.6 1,874 0.9 N/A
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline run. IPM may show partial (i.e., unit) or full plant
early retirements (closures) for a given option. It may also show avoided closures (negative closure values) in which a unit or plant that is
projected to close in the baseline, is estimated to continue operating in the post-compliance case. Avoided closures may occur among plants that incur
no compliance costs or for which compliance costs are low relative to other steam electric plants.\75\
---------------------------------------------------------------------------
\75\ Given the design of IPM, unit-level and thereby plant-level
projections are presented as an indicator of overall regulatory
impact rather than a prediction of future unit- or plant-specific
compliance actions. ERCOT (Electric Reliability Council of Texas),
FRCC (Florida Reliability Coordinating Council), MRO (Midwest
Reliability Organization), NPCC (Northeast Power Coordination
Council), RFC (ReliabilityFirst Corporation), SERC (Southeastern
Electricity Reliability Council), SPP (Southwest Power Pool), and
WECC (Western Electricity Coordinating Council).
---------------------------------------------------------------------------
As shown in Table XI-5, the Market Model Analysis indicates that
Option 3 would have very small effects in overall electricity markets,
on both a national and regional sub-market basis, in the year 2030.
Overall at the national level, the net change in total capacity,
including reductions in capacity (which includes early retirements) and
capacity additions in new plants/units, results in approximately 1GW of
additional capacity (less than 0.05 percent total market capacity),
which is too small to appear in Table XI-5. This increase in capacity
is expected to take place entirely in the SPP NERC region (0.8 percent
of total SPP capacity) and is the result of reduction in retired
capacity (avoided capacity closures) and increase in new capacity and
capacity at existing generating units.\76\ Consequently, Option 3 is
expected to have negligible effect on capacity availability and supply
reliability at the national level. Overall impacts on electricity
prices are similarly minimal. While electricity prices are expected to
increase in all NERC regions, the magnitude of this increase varies
across regions and ranges from $0.03 per MWh (0.1 percent) in MRO to
$0.24 per MWh (0.4 percent) in SERC. Finally, at the national level,
total costs increase by approximately 0.4 percent of the baseline
value--again, a modest amount. Across regions, no NERC region records
an increase in power sector total costs exceeding 1 percent.
---------------------------------------------------------------------------
\76\ Avoided capacity closures occur when one or more generating
units that are otherwise projected to cease operations in the
baseline become more economically attractive sources of electricity
in the post-compliance case, because of relative changes in the
economics of electricity production across the full market, and thus
avoid closure.
---------------------------------------------------------------------------
The findings for Option 4 overall lie very close to those of Option
3. Similar to Option 3, the net change in total capacity under Option 4
is essentially zero, indicating that this option would be expected to
have a negligible effect on capacity availability and supply
reliability, at the national level. This is also the case at the
regional level, with small capacity changes in RFC (early retirement)
and SPP (avoided retirement). Option 4 also has a slight impact on
electricity prices across all NERC regions, with increases of no more
than 0.3 percent and a 0.1 percent reduction in the MRO region. At the
national level, variable production costs--fuel and variable O&M--
increase by $0.18 per MWh or 0.6 percent. While variable costs increase
in all NERC regions, the change varies by region ranging from $0.03 per
MWh in NPCC and WECC to $0.29 in RFC. As expected for Option 4, which
is more expensive than Option 3, the increase in total annual costs for
the electric power sector is greater than under Option 3. At the
national level, total annual costs increase by $1.9 billion (0.9
percent). As discussed in greater detail in Chapter 5 of the RIA
document, the largest shares of this increase occur in variable O&M;
capital costs increase by a much smaller amount. As discussed above,
EPA expects the impacts of Options 3a and 3b to be smaller than those
of Option 3, and the impacts of Option 4a to be between those of
Options 3 and 4.
b. Impact on Existing Steam Electric Plants
EPA used IPM V4.10 results for 2030 to assess the potential impact
of the regulatory options on steam electric plants. In contrast to the
previously described electricity market-level
[[Page 34498]]
analysis, which sought to assess the impact of the proposed ELGs
regulatory options on the entire electric power sector, the purpose of
this second analysis is to assess impacts on steam electric plants
specifically.
Table XI-6 reports results for steam electric plants, as a group.
In this case, EPA looked at the following metrics IPM produces: (1)
Incremental early retirements and capacity closures, calculated as the
difference between capacity under the regulatory options and capacity
under the baseline, which includes both full plant closures and partial
plant closures (i.e., unit closures) in aggregate capacity terms; (2)
incremental capacity closures as a percentage of baseline capacity; (3)
post-compliance change in electricity generation; (4) post-compliance
changes in variable production costs per MWh, calculated as the sum of
total fuel and variable O&M costs divided by net generation; and (5)
changes in annual costs (fuel, variable O&M, fixed O&M, and capital.
Items (1) and (2) are instrumental in determining the economic
achievability of various regulatory options.
Table XI-6--Impact of Market Model Analysis Options on Steam Electric Plants as a Group at the Year 2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
Incremental early retirements/ Change in
closures \a\ Change in total variable Change in annual
NERC region Baseline ------------------------------------ generation (GWh production cost costs (million
capacity (MW) % of Baseline or % of (2010$/MWh or % 2010$ or % of
Capacity (MW) capacity baseline) of baseline) baseline)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3:
ERCOT................................... 32,275 0 0.0 -83 0.0% $0.09 0.3% $35 0.5%
FRCC.................................... 32,227 0 0.0 -25 0.0 0.11 0.3 27 0.4
MRO..................................... 34,899 0 0.0 83 0.0 -0.02 -0.1 26 0.3
NPCC.................................... 16,629 0 0.0 -3 0.0 0.07 0.2 9 0.2
RFC..................................... 122,205 0 0.0 234 0.0 0.15 0.5 225 0.7
SERC.................................... 131,895 0 0.0 -1,140 -0.2 0.24 0.8 283 0.8
SPP..................................... 31,269 -102 -0.3 -123 -0.1 0.04 0.1 15 0.2
WECC.................................... 54,494 0 0.0 103 0.0 0.05 0.2 22 0.2
-----------------------------------------------------------------------------------------------------------
Total............................... 455,894 -102 0.0 -954 0.0 0.13 0.5 642 0.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 4:
ERCOT................................... 32,275 0 0.0 -227 -0.1 0.16 0.5 66 1.0
FRCC.................................... 32,227 0 0.0 78 0.1 0.05 0.1 27 0.4
MRO..................................... 34,899 0 0.0 212 0.1 0.12 0.5 108 1.4
NPCC.................................... 16,629 -431 -2.6 -4 0.0 0.10 0.3 29 0.7
RFC..................................... 122,205 681 0.6 -2,351 -0.3 0.38 1.3 561 1.8
SERC.................................... 131,895 0 0.1 -2,178 -0.3 0.43 1.5 607 1.8
SPP..................................... 31,269 -30 -0.1 -510 -0.3 0.16 0.6 59 0.9
WECC.................................... 54,494 0 0.0 63 0.0 0.07 0.3 46 0.4
-----------------------------------------------------------------------------------------------------------
Total............................... 455,894 317 0.1 -4,916 -0.2 0.28 1.0 1,504 1.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline run. IPM may show partial (i.e., unit) or full plant
early retirements (closures) for a given option. It may also show avoided closures (negative closure values) in which a unit or plant that is
projected to close in the baseline, is estimated to continue operating in the post-compliance case. Avoided closures may occur among plants that incur
no compliance costs or for which compliance costs are low relative to other steam electric plants. \77\
---------------------------------------------------------------------------
\77\ Given the design of IPM, unit-level and thereby plant-level
projections are presented as an indicator of overall regulatory
impact rather than a prediction of future unit- or plant-specific
compliance actions.
---------------------------------------------------------------------------
Under Option 3, the net change in total capacity for steam electric
plants is very small; this is similar to prior findings when
considering the electricity market as a whole. For the group of steam
electric plants, total capacity increases by 106 MW (not shown in Table
XI-6, see RIA for details) or approximately 0.02 percent of the 455,894
MW baseline capacity. This results in part from avoided capacity
closures of 102 MW in the SPP region. Option 3 results in no closures,
full (plant) or partial (unit), in the other seven regions.
The change in total generation is an indicator of how steam
electric plants fare, relative to the rest of the electricity market.
While at the market level there is essentially no projected change in
total electricity generation,\78\ for steam electric plants, total
available capacity and electricity generation at the national level is
projected to fall by less than 0.1 percent. At the regional level, five
NERC regions--ERCOT, NPCC, RFC, SERC, and SPP--are projected to
experience a reduction in electricity generation from steam electric
plants, ranging from 3 GWh in NPCC (less than 0.01 percent) to 1,140
GWh in RFC (0.2 percent). The other three NERC regions are each
projected to experience a very modest increase in electricity
generation from steam electric plants of less than 0.1 percent.
---------------------------------------------------------------------------
\78\ At the national level, the demand for electricity does not
change between the baseline and the analyzed regulatory options
(generation within the regions is allowed to vary) because meeting
demand is an exogenous constraint imposed by the model.
---------------------------------------------------------------------------
Finally, at the national level, variable production costs at steam
electric plants increase by approximately 0.5 percent. These effects
vary by region from about -0.1 percent in MRO to 0.8 percent in SERC.
These findings of very small national and regional effects in these
impact metrics confirm EPA's assessment that Option 3 can be expected
to have little economic consequence in national and regional
electricity markets.
Results of the analysis for Option 4 show almost no change in
either total generating capacity or electricity generation for the
electric power sector as whole, and steam electric generating capacity
and electricity generation fall slightly by 306 MW (0.07 percent) (not
shown in Table XI-6, see RIA for
[[Page 34499]]
details) and 4,916 GWh (0.2 percent), respectively. The steam electric
capacity reduction includes early retirement and avoided retirement of
generating units with the net effect of the two types of changes being
capacity losses. Thus, under the analysis for Option 4, 14 generating
units close (1,125 MW) and 5 generating units avoid closure (808 MW),
leading to an estimated net closure of nine generating units (317 MW,
see Table XI-6). All 14 units that are projected to close in this
scenario are located within six plants that are projected to continue
operating. In other words, Option 4 is not projected to result in any
full plant closures.\79\
---------------------------------------------------------------------------
\79\ Given the design of IPM, unit-level and thereby plant-level
projections are presented as an indicator of overall regulatory
impact rather than a prediction of future unit- or plant-specific
compliance actions.
---------------------------------------------------------------------------
Findings for the change in total costs and variable production
costs under Option 4 also exceed those under Option 3. There is a 1.4
percent increase in total costs at the national level, with SERC
recording the largest increase of 1.8 percent. As detailed in Chapter 5
of the RIA document, at the national level, the increase in total costs
occurs in fixed and variable O&M (3.2 percent and 9.3 percent,
respectively) while fuel costs and capital costs decline (0.4 percent
and 3.2 percent, respectively). At the national level, variable
production costs increase by 1.0 percent, with SERC recording the
highest increase of 1.5 percent. As for impacts on national and
regional markets, EPA expects the impacts on steam electric plants of
Options 3a and 3b to be smaller than those of Option 3, and the impacts
of Option 4a to be between those of Options 3 and 4.
c. Impact on Individual Steam Electric Plants Incurring Compliance
Costs Under This Rulemaking
Results for the group of steam electric plants as a whole may mask
shifts in economic performance among individual plants incurring
compliance costs associated with the proposed ELGs. To assess potential
plant-level effects, EPA analyzed plant-specific changes between the
base case and the post-compliance cases for the following metrics: (1)
Capacity utilization (defined as annual generation (in MWh) divided by
[capacity (MW) times 8,760 hours]) (2) electricity generation, and (3)
variable production costs per MWh, defined as variable O&M cost plus
fuel cost divided by net generation.
Table XI-7 presents the estimated number of plants incurring
compliance costs with specific degrees of change in operations and
financial performance for the two regulatory options EPA analyzed using
IPM. Metrics of interest include the number of plants with reductions
in capacity utilization or generation (on left side of the table), and
the number of plants with increases in variable production costs (on
right side of the table).
Table XI-7--Impact of Market Model Analysis Options on Individual Steam Electric Plants Incurring Compliance Costs at the Year 2030--Number of Plants by
Impact Magnitude
--------------------------------------------------------------------------------------------------------------------------------------------------------
Reduction Increase
Economic measures --------------------------------------- No Change --------------------------------------- N/A \b\
>= 3% >=1 and <3% <1% <1% >=1 and <3% >= 3%
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Change in Capacity Utilization \a\.............. 6 7 62 438 41 4 6 101
Change in Generation............................ 15 3 53 443 38 4 8 101
Change in Variable Production Costs/MWh......... 2 3 183 72 239 28 23 115
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Change in Capacity Utilization \a\.............. 6 4 131 291 113 7 9 104
Change in Generation............................ 12 4 118 302 104 6 15 104
Change in Variable Production Costs/MWh......... 2 2 136 46 225 99 37 118
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The change in capacity utilization is the difference between the capacity utilization percentages in the base case and post-compliance cases. For
all other measures, the change is expressed as the percentage change between the base case and post-compliance values.
\b\ Plants with status changes in either baseline or post-compliance scenario have been excluded from these calculations. For example, for a plant that
is projected to close in the post-compliance case, the reduction in variable costs per MWh of generated electricity would be 100 percent.
Specifically, there are 23 full baseline plant closures, 77 partial baseline plant closures, and 1 avoided plant closure under Option 3. There are 23
full baseline plant closures, 72 partial baseline plant closures, 3 avoided plant closures, and 6 partial policy plant closures under Option 4.
For Option 3, the analysis of changes in individual plants
indicates that most plants experience only slight effects--no change,
or less than a 1 percent reduction or 1 percent increase. Only 13
plants (2 percent) are estimated to incur a reduction in capacity
utilization exceeding 1 percent and 18 plants (3 percent) incur a
reduction in generation exceeding 1 percent. The estimated change in
variable production costs is higher; 51 plants (8 percent) incur an
increase in variable production costs exceeding 1 percent; for 23 of
these plants, this increase exceeds 3 percent.
Results for Option 4 show greater effects as compared to Option 3.
While the difference in the policy impact on capacity utilization and
generation is small, the difference in policy impact on variable costs
is greater. The reduction in capacity utilization and generation is
estimated to exceed 1 percent for 10 and 16 plants (approximately 2
percent), respectively. The increase in variable production costs is
estimated to exceed 1 percent for 136 plants, 99 of which have an
increase between 1 and 3 percent.
As for the market and industry-level results discussed above, EPA
expects the impacts of Options 3a and 3b to be smaller than those of
Option 3, and the impacts of Option 4a to be between those of Options 3
and 4.
3. Summary of Economic Impacts for Existing Sources
EPA performed cost and economic impact assessment in two parts. The
first set of cost and economic impact analyses--including entity-level
impacts at both the plant and parent company levels--reflects baseline
operating characteristics of plants incurring compliance costs and
assumes no changes in those baseline operating characteristics (e.g.,
level of electricity generation and revenue) as a result of the
requirements of the proposed regulatory options. They can serve as
screening-level indicators of the relative cost of different regulatory
options to plants, owning entities, or consumers, but are not
determinative in terms of
[[Page 34500]]
assessing the economic achievability of various regulatory options.
The second set of analyses look at broader electricity market
impacts taking into account the interconnection of regional and
national electricity markets, for the full industry, for steam electric
plants only, and at the distribution of impacts at the plant level.
This second analysis provides insight on the impacts of the proposed
ELGs on steam electric plants, as well as the electricity market as a
whole, including generation capacity closure, and changes in generation
and wholesale electricity prices. Results of the Market Model for
Option 3 show no incremental plant closures (complete or partial) and
relatively small changes in production costs. This analysis shows that
Option 3 for existing steam electric plants is economically achievable.
This same conclusion applies to Options 3a and 3b since the costs of
these options are less than those of Option 3.
The Market Model analysis of Option 4 shows slightly higher, but
still relatively small, impacts on steam electric generation and
individual plants as compared to Option 3. For example, the results
show incremental partial capacity retirements of 317 MW at the national
level (1.4 percent relative to the baseline without the proposed ELGs),
no full plant retirements, and greater increases in production costs
(1.0 percent), as compared to Option 3. Given these impacts, and since
the impacts of Option 4a would fall between those of Options 3 and 4,
EPA believes that Option 4a is also economically achievable.
4. Summary of Economic Impacts for New Sources
Electric power generating units that meet the definition of a new
source would be required to meet the proposed NSPS or PSNS. EPA
developed estimated compliance costs for new units using a methodology
similar to that used to develop compliance costs for existing plants,
with the notable exception that EPA did not develop new unit compliance
costs that are plant specific, which would require EPA to predict which
plants will construct new units.
EPA assessed the possible impact of incremental costs associated
with this proposal for new units in two ways: (1) As part of its
analysis using IPM discussed in Section XI.D.3; and (2) by comparing
the incremental costs for new units to the overall cost of building and
operating new scrubbed coal units.
EPA estimated the incremental capital and fixed O&M costs for each
new electricity generating coal unit projected to come online in IPM.
The Agency estimated variable O&M costs assuming that any new unit
would operate, on average, 330 days per year. IPM takes these
additional regulatory costs into account when trying to determine the
least costly means of meeting the total electricity demand. Results of
the IPM analysis are summarized in Section XI.D.3 of this preamble and
discussed in detail in Chapter 5 of the RIA document. IPM results show
no barrier to new generation capacity for 2025-2034 as a result of
compliance with the preferred NSPS/PSNS regulatory options (Option 4).
The model estimates no change in coal steam capacity relative to the
baseline, and small increases in generation capacity from other steam
(0.3 percent), combustion turbine (0.3 percent), other non-steam (less
than 0.1 percent), and combined cycle (less than 0.1 percent)
units.\80\
---------------------------------------------------------------------------
\80\ Other steam generation includes biomass, landfill gas,
fossil waste, municipal solid waste, non-solid waste, tires, and
geothermal. Other non-steam generation includes wind, solar, pumped
storage, and fuel cell.
---------------------------------------------------------------------------
As a separate analysis, EPA also compared total compliance costs to
the total cost of building and operating a new coal unit on an
annualized basis. EPA obtained the overnight \81\ capital and O&M costs
of building and operating a new scrubbed coal unit used in the Energy
Information Administration's Annual Energy Outlook 2011; these costs
were estimated for a new dual-unit plant with a total generation
capacity of 1,300 MW. Table XI-8 shows capital and O&M costs of
building and operating a new coal unit and contrasts these costs with
the incremental costs associated with the preferred option (i.e.,
Option 4 for new sources).
---------------------------------------------------------------------------
\81\ As defined by the Energy Information Administration,
``overnight cost'' is an estimate of the cost at which a plant could
be constructed assuming that the entire process from planning
through completion could be accomplished in a single day. This
concept is useful to avoid any impact of project delays and of
financing issues and assumptions on estimated costs.
Table XI-8--Comparison of Incremental Compliance Costs with Costs for New Coal-Fired Steam Electric Units
----------------------------------------------------------------------------------------------------------------
Costs of new coal Incremental
Cost component generation compliance costs Percent of new
($2010/MW) \a\ ($2010/MW) \b\ generation cost
----------------------------------------------------------------------------------------------------------------
Capital................................................ $2,981,947 $19,911-$21,773 0.7-0.7
Annual O&M............................................. 66,427 2,281-$3,093 3.4-4.7
--------------------------------------------------------
Total Annualized Costs................................. 329,487 4,037-$5,013 1.2-1.5
----------------------------------------------------------------------------------------------------------------
\a\ Source: New unit total cost value from Table 8.2 EIA NEMS Electricity Market Module. AEO 2011 Documentation.
Available at http://www.eia.gov/forecasts/aeo/assumptions/pdf/electricity.pdf. Capital costs are based on the
total overnight costs for new scrubbed coal dual-unit plant, 1,300 MW capacity coming online in 2014. EPA
restated costs in 2010 dollars. Total annual O&M costs assume 90% capacity utilization.
\b\ Incremental costs for new 1300 MW unit for Option 4. Range represents the costs for a new unit at an
existing plant (lower bound) and new unit at newly constructed plant (upper bound).
The comparison suggests that compliance with the proposed ELGs
represents a relatively small fraction of overnight capital costs of a
new unit (less than 1 percent) and a somewhat higher, but still small
(less than 5 percent), fraction of non-fuel O&M costs. On an annualized
basis, compliance costs for the proposed ELGs are 1.2 to 1.5 percent of
annualized costs for a new plant.
Based on these two separate assessments, EPA finds no evidence that
the incremental compliance costs associated with the proposed NSPS/PSNS
present a barrier to entry.
5. Assessment of Potential Electricity Price Effects
EPA assessed the potential electricity price effects of this
proposed rule in two ways: (1) an assessment of the potential annual
increase in household electricity costs and (2) an assessment of the
potential annual increase in electricity costs per MWh of total
electricity sales.
[[Page 34501]]
The analysis assumes, for analytic convenience as a worst-case
scenario, that all compliance costs will be passed through on a pre-tax
basis as increased electricity prices as opposed to the treatment in
the plant- and entity-level analyses discussed in Section XI.D.1 above,
which assume that none of the compliance costs will be passed to
consumers through electricity rate increases.
a. Cost to Residential Households
Using the assumptions outlined above, EPA estimated the potential
annual increase in electricity costs per household, by North American
Electric Reliability Corporation (NERC) region. The analysis uses the
total annualized pre-tax compliance cost per megawatt hour (MWh) for
the year 2014 (in 2010 dollars), in conjunction with the reported total
electricity sales quantity for each NERC region for 2009. This analysis
also uses the quantity of residential electricity sales per household
in 2009. To calculate the average cost per household, by region, EPA
divided total compliance costs for each NERC region by the reported
total MWh of sales within the region. The potential annual cost impact
per household was then calculated by multiplying the estimated average
cost per MWh by the average MWh per household, by NERC region.\82\
Details of this analysis are presented in Chapter 7 of the RIA.
---------------------------------------------------------------------------
\82\ Some NERC regions have been re-defined over the past few
years. The NERC region definitions used in this proposed rule
analyses vary by analysis depending on which region definition
aligns better with the data elements underlying the analysis.
---------------------------------------------------------------------------
Table XI-9 summarizes the annual household impact results for each
regulatory option, by NERC region. The results for Option 3a show the
average annual cost per residential household increasing by $0 to $1.69
depending on the region, with a national average of $0.48. This
represents a monthly increase of $0.04 for the typical household. For
Option 3b, the results show the average annual cost per residential
household increasing by $0 to $2.29, with a national average of $0.75,
or $0.06 per month. For Option 3, the average annual cost per
residential household increases by $0 to $4.40, with a national average
of $1.59, or $0.13 per month. Finally, for Option 4a, the average
annual cost per residential household increases by $0 to $7.22,
depending on the region, with a national average of $2.69, or $0.22 per
month.
Table XI-9--Average Annual Cost Burden per Residential Household in 2014 by Regulatory Option and NERC Region
[2010$] \a\
----------------------------------------------------------------------------------------------------------------
Option Option Option
NERC Region 3a 3b Option 1 Option 2 Option 3 4a Option 4 Option 5
----------------------------------------------------------------------------------------------------------------
ASCC............................ $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
ECAR............................ 1.69 2.29 1.82 2.71 4.40 7.22 10.08 16.86
ERCOT........................... 0.00 0.42 1.22 1.73 1.73 2.60 2.79 5.76
FRCC............................ 0.00 0.00 0.18 0.67 0.67 0.67 0.99 4.32
HICC............................ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
MAAC............................ 0.00 0.00 0.06 0.32 0.32 0.97 2.04 3.52
MAIN............................ 0.31 0.31 0.48 0.69 1.01 2.55 4.63 6.16
MAPP............................ 0.01 0.01 0.97 1.30 1.32 2.04 3.23 5.58
NPCC............................ 0.00 0.00 0.03 0.08 0.08 0.08 0.49 0.67
SERC............................ 1.09 2.00 1.63 2.19 3.28 4.98 6.47 10.81
SPP............................. 0.05 0.14 0.61 0.96 1.01 2.85 4.43 6.30
WECC............................ 0.05 0.05 0.02 0.03 0.08 0.23 0.53 0.59
U.S............................. 0.48 0.75 0.75 1.12 1.59 2.69 3.89 6.46
----------------------------------------------------------------------------------------------------------------
\a\ The rate impact analysis maintains the counterfactual, conservative assumption of 100 percent pass-through
to electricity consumers.
As stated above, this analysis assumes that all of the compliance
costs (100 percent) will be passed onto consumers through increased
electricity rates. However, plants and owning entities are likely to
absorb some of these costs, thereby reducing the impact of the proposed
ELGs on electricity consumers. At the same time, EPA recognizes that
electric generators that operate as regulated public utilities are
generally permitted to pass on environmental compliance costs as rate
increases to consumers. To evaluate the sensitivity of the results to
the pass-through assumption, EPA analyzed alternative scenarios
including cases where only half (50 percent) of the incremental
compliance costs are passed onto consumers. Appendix B of the RIA
report presents the results of this sensitivity analysis. The results
show smaller impacts on electricity rates, commensurate with the
smaller fraction of the compliance costs that are passed onto
consumers.
b. Compliance Costs per Unit of Electricity Sales
As an additional measure of the potential electricity price effects
associated with the proposed ELGs, EPA also assessed the potential
increase in electricity prices to all consumer groups (residential,
commercial, industrial, and transportation), again making a
counterfactual, conservative assumption of a 100 percent pass-through
of compliance costs. This assessment uses as its basis the cost of the
regulatory options per unit of electricity sold.
EPA used two data inputs in this analysis (1) total pre-tax
compliance cost by NERC region, and (2) estimated total electricity
sales for 2014, by NERC region. The Agency summed sample-weighted pre-
tax annualized compliance costs as of 2014 over complying plants by
NERC region to calculate the total estimated annual cost in each
region. EPA then calculated the approximate average price impact per
unit of electricity consumption by dividing total compliance costs by
the reported total MWh of sales in each NERC region. Details of this
analysis are presented in Chapter 7 of the RIA report.
As reported in Table XI-10, on average, across the United States,
Option 5 results in the highest increased compliance cost of
0.059[cent] per kWh. Annualized compliance costs (in dollars per KWh
sales) associated with Option 3a range from 0[cent] to 0.016[cent],
depending on the region, with a national average of
[[Page 34502]]
0.004[cent] per KWh. For Option 3b, annualized compliance costs range
from 0[cent] to 0.022[cent], with a national average of 0.007[cent] per
KWh, whereas Option 3 has a range of 0[cent] to 0.042[cent] per kWh and
a national average of 0.015[cent] per kWh and Option 4a has a range of
0[cent] to 0.068[cent] per kWh and a national average of 0.025[cent]
per kWh. To determine the potential significance of these compliance
costs on electricity prices, EPA compared the per kWh compliance cost
to baseline electricity prices by consuming sector, and for the average
of the sectors. Across the United States and consuming sectors, Option
3a is estimated to result in the smallest electricity price increase,
0.05 percent; the other preferred BAT and PSES options, Options 3b, 3
and 4a, have estimated increases of 0.08 percent, 0.16 percent and 0.27
percent, respectively.
Table XI-10--Compliance Cost per Unit of Electricity Sales in 2014 by Regulatory Option and NERC Region
[2010 [cent]/KWh Sales] \a\
----------------------------------------------------------------------------------------------------------------
Option Option Option
NERC Region 3a 3b Option 1 Option 2 Option 3 4a Option 4 Option 5
----------------------------------------------------------------------------------------------------------------
ASCC............................ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
ECAR............................ 0.016 0.022 0.017 0.026 0.042 0.068 0.095 0.159
ERCOT........................... 0.000 0.003 0.009 0.012 0.012 0.019 0.020 0.041
FRCC............................ 0.000 0.000 0.001 0.005 0.005 0.005 0.007 0.032
HICC............................ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
MAAC............................ 0.000 0.000 0.001 0.003 0.003 0.010 0.021 0.036
MAIN............................ 0.003 0.003 0.005 0.008 0.011 0.028 0.051 0.068
MAPP............................ 0.000 0.000 0.009 0.012 0.013 0.019 0.031 0.053
NPCC............................ 0.000 0.000 0.000 0.001 0.001 0.001 0.007 0.009
SERC............................ 0.008 0.014 0.012 0.016 0.023 0.035 0.046 0.076
SPP............................. 0.000 0.001 0.005 0.008 0.008 0.023 0.036 0.051
WECC............................ 0.001 0.001 0.000 0.000 0.001 0.002 0.006 0.006
U.S............................. 0.004 0.007 0.007 0.010 0.015 0.025 0.036 0.059
----------------------------------------------------------------------------------------------------------------
\a\ This analysis makes a counterfactual, conservative assumption of 100 percent pass-through to electricity
consumers.
As mentioned in the previous section, EPA ran alternative scenarios
using an assumption that only half (50 percent) of the incremental
compliance costs are passed onto consumers. The results of these
alternative scenarios showed commensurately smaller impacts on
compliance costs per unit of electricity sold (see Appendix B of the
RIA report).
E. Employment Effects
EPA assessed the potential for employment impacts at the national
level for the eight regulatory options considered in this action.
1. Methodology
The employment effects analysis estimates employment changes only
in the directly regulated electric power industry sector at the
national level. This analysis focuses on the longer-term, on-going
employment effects of meeting compliance requirements, and accounts for
all compliance costs, regardless of their time, duration, or frequency
of occurrence. Morgenstern, Pizer and Shih (2000) explore both
theoretically and empirically the relationship between employment and
compliance costs of environmental regulation. Morgenstern et al.
identify three separate components of the employment change within a
regulated industry in response to a regulation. First, complying with
environmental regulations causes higher production costs which raises
market prices, higher prices reduce consumption (and production)
reducing demand for labor within the regulated industry (``demand
effect''). Second, as costs go up, to produce the same level of output,
plants add more capital and labor. For example, pollution abatement
activities require additional labor services to produce the same level
of output (``cost effect''). Third, post-regulation production
technologies may be more or less labor intensive (i.e., more/less labor
is required per dollar of output) (``factor-shift effect''). The demand
effect is unambiguously negative, the cost effect is unambiguously
positive and the factor-shift effect could be positive or negative
making the total effect theoretically indeterminate. In addition,
Morgenstern et al. also estimate an empirical model for four highly
polluting/regulated industries to examine the effect of higher
abatement costs from regulation on employment. They conclude that
increased abatement expenditures generally do not cause a significant
change in employment. More specifically, their results show that, on
average across their industries, each additional $1 million spending on
pollution abatement (in $1987 dollars) results in a (statistically
insignificant) net increase of 1.5 jobs (95 percent confidence
interval: -2.9 to + 6.0).
2. Findings
Table XI-11 presents the estimated change, based on the Morgenstern
et al. results, in employment in the electric power industry due to the
proposed ELGs under each of the eight regulatory options. The table
lists the options in increasing order of employment effects. Overall,
in the aggregate and by a specific employment effect, Option 1 is
projected to have the smallest effect and Option 5 is projected to have
the largest effect on employment. The Demand Effect is projected to
result in a decline in the number of jobs, while the Cost Effect and
Factor Shift Effect are projected to result in an increase in the
number of jobs.
EPA estimated an average annual increase of 168 jobs under proposed
Option 3a for existing sources. For proposed Option 3b, the average
annual increase is estimated at 255 jobs, whereas Options 3 and 4a have
estimated increases of 519 jobs and 865 jobs, respectively. Because the
electric utility industry is more capital intensive and less labor
intensive than the industries examined in Morganstern, Pizer and Shih,
in addition to the employment estimates being statistically not
distinguishable from the effect being zero, the estimates presented
here are likely to be over-estimated. Chapter 6 of the RIA report
describes the methodologies and results in greater detail.
[[Page 34503]]
Table XI-11--Results of Ongoing Employment Effects on the Electric Power
Industry Sector (Number of Jobs) a b
------------------------------------------------------------------------
Total annual
average
Regulatory option Employment effect employment
effect
------------------------------------------------------------------------
Option 3a......................... Cost.................. 262
Factor Shift.......... 291
Demand................ -386
-------------------------------------
Total.............. 168
------------------------------------------------------------------------
Option 1.......................... Cost.................. 380
Factor Shift.......... 421
Demand................ -559
-------------------------------------
Total.............. 243
------------------------------------------------------------------------
Option 3b......................... Cost.................. 399
Factor Shift.......... 441
Demand................ -586
-------------------------------------
Total.............. 255
------------------------------------------------------------------------
Option 2.......................... Cost.................. 548
Factor Shift.......... 607
Demand................ -806
-------------------------------------
Total.............. 548
------------------------------------------------------------------------
Option 3 Cost.................. 810
Factor Shift.......... 897
Demand................ -1,192
-------------------------------------
Total.............. 519
------------------------------------------------------------------------
Option 4a......................... Cost.................. 1,351
Factor Shift.......... 1,496
Demand................ -1,988
-------------------------------------
Total.............. 865
------------------------------------------------------------------------
Option 4.......................... Cost.................. 1,956
Factor Shift.......... 2,166
Demand................ -2,878
-------------------------------------
Total.............. 1,253
------------------------------------------------------------------------
Option 5.......................... Cost.................. 3,298
Factor Shift.......... 3,653
Demand................ -4,852
-------------------------------------
Total.............. 2,112
------------------------------------------------------------------------
\a\ Source: Morgenstern, Pizer, and Shih (2002).
\c\ Coefficients from Table III, p. 427, for the Cost, Demand, Factor
Shift and Total Effects were multiplied by the annualized cost of the
proposed ELGs calculated as part of the social cost analysis (see
Section XI.C) during the 24-year analysis period and re-stated in 1987
dollars, by the coefficient for the net increase in jobs.
Number of jobs is the average number of production workers plus other
employees. The definition for employment used by the U.S. Census
Bureau's Annual Survey of Manufacturers can be found here: http://www.census.gov/manufacturing/asm/definitions/index.html.
XII. Cost-Effectiveness Analysis
EPA performed a cost-effectiveness analysis of the regulatory
options for existing plants. EPA often uses cost-effectiveness analysis
in the development/revision of effluent limitations guidelines and
standards to evaluate the relative efficiency of alternative regulatory
options in removing toxic pollutants from the effluent discharges to
the nation's waters. Although not required by the Clean Water Act,
cost-effectiveness analysis is a useful tool for evaluating regulatory
options that address toxic pollutants.
A. Methodology
The cost-effectiveness of a regulatory option is defined as the
incremental annual cost (in 1981 constant dollars) per incremental
toxic-weighted pollutant removals for that option. This definition
includes the following concepts:
Toxic-weighted removals. Pollutants differ in their toxicity.
Therefore, the estimated reductions in pollution discharges, or
pollutant removals, are adjusted for toxicity by multiplying the
estimated removal quantity for each pollutant by a normalizing toxic
weight (toxic weighting factor). The toxic weight for each pollutant
measures its toxicity relative to copper, with more toxic pollutants
having higher toxic weights. The use of toxic weights allows the
removals of different pollutants to be expressed on a constant toxicity
basis as toxic pound-equivalents (lb-eq). The removal quantities for
the different pollutants can then be summed to yield an aggregate
measure of the reduction in toxicity-normalized pollutant discharges
that is achieved by a regulatory option. The cost-effectiveness
analysis does not address the removal of conventional pollutants (e.g.,
total suspended solids) or nutrients (nitrogen, phosphorus), nor does
it address the removal of bulk parameters, such as COD. In the case of
indirect dischargers, the removal also accounts for the effectiveness
of treatment at publicly owned treatment works (POTW) and reflects the
toxic-weighted pounds remaining after POTW treatment.
Annual costs. The costs used in the cost-effectiveness analysis are
the estimated annualized pre-tax costs to comply with the alternative
regulatory options (refer to Section XI for a discussion of the
annualized compliance costs). These costs to plants to remove the
pollutants will be less because the costs are tax deductible. The
annual costs include the annualized capital outlays for equipment and
recurring expenses for operating and maintaining compliance equipment,
meeting monitoring requirements, etc.
Incremental calculations. The incremental values are the changes in
total annual compliance costs and changes in pollutant removals as one
moves to a regulatory option from the next less stringent regulatory
option, or from the baseline for the least stringent option analyzed,
where regulatory options are ranked by increasing levels of toxic-
weighted removals. The resulting cost-effectiveness values for a given
option are, therefore, expressed relative to another option or, for the
least stringent option considered, relative to the baseline.
The result of the cost-effectiveness calculation represents the
unit cost of removing the next pound-equivalent of pollutants and is
expressed in constant 1981 dollars per toxic pound-equivalent removed
($/lb-eq) to allow comparisons with the reported cost effectiveness of
other effluent guidelines, which use 1981 dollars.
EPA performed the cost-effectiveness analysis for the eight
regulatory options for the proposed Steam Electric ELGs separately for
existing direct dischargers (subject to BAT) and indirect dischargers
(subject to PSES). The following sections summarize the results. Note
that the same plant may be categorized as a direct discharger for one
of the wastestreams it generates and as an indirect discharger for
another.
B. Cost-Effectiveness Analysis for Direct Dischargers
Table XII-1 summarizes the cost-effectiveness analysis for the BAT
regulatory options applicable to direct dischargers. The table lists
the options in increasing order of total annual toxic-weighted
pollutant removals.
[[Page 34504]]
Table XII-1--Cost-Effectiveness of Removing Toxic Pollutants for Direct Dischargers a
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual pre-tax compliance costs Total annual toxic-weighted Cost effectiveness (1981$/lb-
(million, 1981$) pollutant removals (000 lb-eq) eq)
-----------------------------------------------------------------------------------------------------
Option Incremental
Option total Incremental Option total Incremental Option cost cost
cost cost removals removals effectiveness effectiveness
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 1.......................................... $105.6 $105.6 1,530,719 1,530,719 $69 $69
Option 3a......................................... 67.5 -38.1 2,488,470 957,751 27 -40
Option 2.......................................... 156.0 88.5 2,603,628 115,158 60 768
Option 3b......................................... 106.3 -49.7 3,396,653 793,025 31 -63
Option 3.......................................... 223.5 117.2 5,092,098 1,695,445 44 69
Option 4a......................................... 378.7 155.2 6,664,693 1,572,595 57 99
Option 4.......................................... 547.9 169.2 7,831,298 1,166,605 70 145
Option 5.......................................... 906.5 358.5 8,200,804 369,506 111 970
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Options are ranked by increasing levels of total annual toxic-weighted removals.
As shown in Table XII-1, the proposed technology bases for BAT have
a cost-effectiveness ratio of $27/lb-eq, $31/lb-eq, $44/lb-eq, and $57/
lb-eq, respectively for Options 3a, 3b, 3 and 4a ($1981). These cost-
effectiveness ratios are well within the range of cost-effectiveness
ratios for BAT of other industries. A review of approximately 25 of the
most recently promulgated or revised BAT limitations shows BAT cost-
effectiveness ranging from less than $1/lb-eq (Inorganic Chemicals) to
$404/lb-eq (Electrical and Electronic Components), in 1981 dollars.
C. Cost-Effectiveness Analysis for Indirect Dischargers
Table XII-2 summarizes the cost-effectiveness analysis for the PSES
regulatory options applicable to indirect dischargers. Toxic-weighted
pollutant removals for indirect dischargers account for POTW removal
efficiencies. The table lists the options in increasing order of total
annual toxic-weighted pollutant removals.
Table XII-2--Cost-Effectiveness of Removing Toxic Pollutants for Indirect Dischargersa
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual pre-tax compliance costs Total annual toxic-weighted Cost effectiveness (1981$/lb-eq)
(million, 1981$) pollutant removals (000 lb-eq) ---------------------------------
Option -------------------------------------------------------------------- Incremental
Option total Incremental Option total Incremental Option cost cost
cost cost removals removals effectiveness effectiveness
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3a......................................... $0.0 $0.0 0 0 ............... ...............
Option 3b......................................... 0.0 0.0 0 0 ............... ...............
Option 1.......................................... 1.2 1.2 3,540 3,540 $345 $345
Option 2.......................................... 2.0 0.7 11,711 8,171 168 92
Option 3.......................................... 2.0 0.0 11,711 0 168 ...............
Option 4a......................................... 2.0 0.0 11,711 0 168 ...............
Option 4.......................................... 3.6 1.6 15,532 3,821 233 430
Option 5.......................................... 8.1 4.5 18,297 2,765 445 1,636
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Options are ranked by increasing levels of total annual toxic-weighted removals.
As shown in Table XII-2, there are no indirect dischargers that
would incur compliance costs or result in incremental pollutant
removals under Options 3a and 3b, whereas Options 3 and 4a both have a
cost effectiveness of $168/lb-eq ($1981). The cost-effectiveness of
Options 3 and 4a is within the range of cost-effectiveness for PSES of
other industries. A review of approximately 25 of the most recently
promulgated or revised categorical pretreatment standards shows PSES
cost-effectiveness ranging from less than $1/lb-eq (Inorganic
Chemicals) to $380/lb-eq (Transportation Equipment Cleaning), in 1981
dollars.
XIII. Environmental Assessment
This section describes the environmental assessment conducted in
support of this rulemaking. The environmental assessment reviewed
currently available literature on the documented environmental and
human health impacts of combustion wastewaters and conducted modeling
to determine the cumulative impacts caused by the universe of steam
electric power plants proposed to be regulated under this effluent
limitations guidelines and standards. Modeling calculated both the
impacts at baseline conditions (current conditions), and the
improvements that will result after implementation of the different
potential control options. The environmental improvements discussed in
Section XIII.A below are those for the preferred BAT and PSES
regulatory options (Option 3a, Option 3b, Option 3, and Option 4a).
A complete review of the scientific literature and a full
description of EPA's modeling analysis (including the results for all
other control options) are provided in the Environmental Assessment of
the Proposed Effluent Limitations Guidelines and Standards for the
Steam Electric Power Generating Point Source Category.
Current scientific literature indicates that combustion wastewaters
such as fly ash and bottom ash transport water, FGD wastewater, and
combustion residual leachate are toxic wastes and are causing
significant detrimental environmental and human health impacts.
Documented environmental impacts from exposure to these wastes reveals
that the threat posed to human health, wildlife and the environment is
a widespread problem that is not isolated to a few unique locations or
circumstances. Documented instances of drinking water maximum
contaminant
[[Page 34505]]
level (MCL) exceedances near steam electric power plants and the
issuance of fish advisories in waters that receive combustion
wastewater indicates the likely threat of human health impacts from
these wastestreams (see Section 3.4.2 of the Environmental Assessment).
In addition, one recent study provides confirming empirical evidence
that toxic wastes are currently damaging aquatic life and accumulating
in the environment and will only get worse.\83\
---------------------------------------------------------------------------
\83\ Ruhl, L., A. Vengosh, G.S. Dwyer, H. Hsu-Kim, G. Schwartz,
A. Romanski, and S.D. Smith. 2012. The Impact of Coal Combustion
Residue Effluent on Water Resources: A North Carolina Example.
Environmental Science and Technology. DCN SE01984.
---------------------------------------------------------------------------
Ecological impacts include both acute (e.g., fish kills) and
chronic effects (e.g., malformations, and metabolic, hormonal, and
behavioral disorders) upon biota within the receiving water and the
surrounding environment. Bioaccumulative toxic metals (e.g., selenium,
mercury, and arsenic) are commonly cited as the primary cause for
ecological damage following exposure to combustion wastewater. Selenium
is the most frequently cited metal associated with environmental
impacts following exposure to combustion wastewater discharges.
Documented selenium-related impacts include lethal effects such as fish
kills and sublethal effects such as histopathological changes (i.e.,
accumulation of trace elements in tissue) and damage to reproductive
and developmental success. Other metals in combustion wastewater
discharges such as arsenic, cadmium, chromium, copper, and lead have
also been documented as causing sublethal effects such as changes to
morphology (e.g., fin erosion, oral deformities), behavior (e.g.,
swimming ability, ability to catch prey, ability to escape from
predators), and metabolism that can negatively affect long-term
survival. Combined, these impacts can drastically alter aquatic
populations and communities and the surrounding ecosystems that rely on
them.
Recovery of the environment from exposure to combustion wastewater
discharges can be extremely slow due to the accumulation and continued
cycling of contaminants within the ecosystem and the potential to alter
ecological processes, such as population diversity and community
dynamics in the surrounding ecosystems. The ability of aquatic and
adjacent terrestrial environments to recover from even short periods of
exposure to these wastes depends on, among other factors, the distance
from the discharge, the pollutant loadings, pollutant residence time,
and the time elapsed since exposure. In particular, accumulation of
metals in sediments can make recovery of aquatic systems following
exposure to combustion wastewater discharges exceptionally slow due to
the potential for resuspension in the water column and for benthic
organisms to provide a pathway for exposure long after discharges have
ended. In addition, metals such as selenium and arsenic bioaccumulate
in organisms exposed to combustion wastewater discharges further
complicating the potential magnitude of impacts these wastes pose.
EPA identified several cases in the literature where metals from
combustion wastewater discharges bioaccumulated to toxic levels in
organisms inhabiting aquatic environments even with low concentrations
of these contaminants. The strong bioaccumulative properties of the
pollutants, in conjunction with long residence times, emphasize the
threat these wastes present to the local environment as many of the
impacts may not be fully realized for years to come.
In addition to the bioaccumulative and toxic properties of the
pollutants in combustion wastewaters, the total pollutant loadings
associated with these discharges are large (see Section IX). EPA
estimates that discharges from steam electric power plants alone
contribute 50 to 60 percent of the reported toxic-weighted pollutant
loadings of the combined discharges of all industrial categories
currently regulated in the U.S. Further, many steam electric power
plants discharge to sensitive environments where pollutant loadings
contribute to reduced water quality (e.g., Great Lakes, valuable
estuaries, 303(d) listed waters, drinking water sources, and waters
with fish consumption advisories).
EPA has determined that 25 percent of surface waters that receive
combustion wastewater discharges are impaired for a pollutant
associated with combustion wastewater; 38 percent of surface waters are
under a fish advisory for a pollutant associated with combustion
wastewater. In addition to the concurrence of combustion wastewater
discharges in close proximity to sensitive environments, EPA has
identified over 120 steam electric power plants with documented
environmental impacts to surface water and ground water environments
following exposure to combustion wastewater, which is further evidence
these wastes are of great concern. While in the past these cases may
have been assumed to be anomalies, an increasing amount of evidence
indicates that the characteristics contributing to the documented
impact (e.g., size of the pollutant loadings, type of pollutant present
in the waste, plant operations, and wastewater handling techniques) are
common among power plant discharge locations. Further, as explained
earlier, these documented impacts do not yet reflect the increased
pollutant loadings associated with increasing use of air pollution
controls. This, when coupled with the potential for long-term
persistent impacts due to bioaccumulative pollutants, indicates that
these impacts most likely are occurring in other locations around the
country even though they have not yet been documented. This suggests
that the magnitude of the environmental impact of combustion wastewater
discharges is potentially greater than the literature estimates.
In addition, EPA has identified other potential impacts from
combustion wastewater discharges. Steam electric plants also discharge
bromide in large quantities. Bromide in wastewater discharges from
steam electric plants located upstream from a drinking water intake has
been associated with the formation of trihalomethanes (THMs) and
haloacetic acids (HAAs) when it is exposed to chlorination disinfection
processes in drinking water treatment plants. Bromate, a disinfection
byproduct (DBP) associated with drinking water treatment plants that
employ ozonation may also increase under the influence of increased
bromide in the source water. Human exposure to THMs and DBPs in
chlorinated drinking water is associated with bladder cancer.
Based on the documented environmental impacts discussed in the
literature, EPA identified several key environmental and human health
concerns and pathways of exposure to evaluate in the environmental
assessment. These included changes in surface water, sediment, and
ground water quality; toxic effects on aquatic life; toxic metal
bioaccumulation in fish and in piscivorous wildlife (e.g., minks and
bald eagles); toxic metal bioaccumulation in fish consumed by humans;
and contamination of ground water drinking water resources.
EPA developed a three-part receiving water model to quantify
changes in plant-specific impacts to surface waters, wildlife, and
human health from pollutant reductions associated with the regulatory
options discussed in Section VIII for a subset of evaluated
wastestreams from steam electric power plants (i.e., fly ash and bottom
ash transport water, FGD wastewater, and leachate). EPA considered the
type of
[[Page 34506]]
receiving waters commonly impacted by steam electric power plants and
the pollutants typically found in the evaluated wastestreams in
selecting the appropriate methodologies for the quantitative
Environmental Assessment analysis. EPA designed the model to quantify
the environmental impact within rivers/streams and lakes/ponds
(including reservoirs) based on the finding that 94 percent of the
power plant outfalls discharge to these types of surface waters. EPA
focused the modeling on toxic metals due to the total mass loadings
discharged, potential for toxic effects to wildlife and human health,
and potential for bioaccumulation within the ecosystem. EPA addressed
environmental impacts from nutrients, in a separate analysis discussed
in Section XIII.E.
EPA's environmental assessment modeling includes three interrelated
models: 1) a receiving water-scale water quality model; 2) a receiving
water-scale wildlife model; and 3) a receiving water-scale human health
model. Each of these models evaluates changes in environmental and
human health effects under baseline conditions and five of the
regulatory options discussed in Section VIII of this preamble (Options
1, 2, 3, 4, and 5). The receiving water-scale water quality model
estimates the concentration of metals (i.e., arsenic, cadmium, chromium
VI, copper, lead, mercury, nickel, selenium, thallium, zinc) in the
surface waters and sediments in the immediate discharge zone (i.e.,
approximately one to 10 kilometers [km] from the outfall) for steam
electric power plants with direct discharge loadings included in the
costs and loadings analysis (see Section IX). EPA compared modeled
receiving water concentrations based on pollutant loadings from the
evaluated wastestreams against National Recommended Water Quality
Criteria (NRWQC) and Maximum Contaminant Levels (MCLs) to assess
changes in receiving water quality. The wildlife model evaluates the
potential impact that water and sediment concentrations pose to aquatic
life, calculates the metal concentrations in exposed fish populations,
and evaluates the potential impact to wildlife (minks and eagles) from
consumption of fish. The human health model calculates potential threat
to cause non-cancer health effects and cancer risks to human
populations from the consumption of fish exposed to discharges of the
evaluated wastestreams. In addition to the immediate receiving water
analysis, EPA modeled receiving water concentrations downstream from
steam electric discharges using EPA's Risk-Screening Environmental
Indicators (RSEI) model and used the wildlife and human health models
to calculate metal concentrations in exposed fish populations and human
exposure doses from fish consumption in surface waters downstream from
steam electric discharges. EPA compared downstream receiving water
concentrations, fish tissue concentrations, and human exposure to water
quality, wildlife, and non-cancer and cancer benchmarks to assess the
number of improved river miles associated with the different options
for this proposed rule.
EPA did not perform modeling to evaluate changes in environmental
and human health effects under Option 3a, Option 3b, or Option 4a. To
estimate the environmental improvements under these three options, the
Agency compared their pollutant load reductions to those of Option 3
(whose reductions would be greater than those of Option 3a and Option
3b, and less than those of Option 4a) and applied corresponding
adjustments to the modeled environmental improvements under Option 3 to
approximate those of the three un-modeled options.
EPA expects a number of environmental and ecological improvements
and reduced impacts to wildlife and human receptors to result from
reductions in effluent loadings examined for the different options
discussed in this proposed rule. In particular, the Environmental
Assessment evaluated the following: a) improvements in water quality,
b) reduction in impacts to wildlife, c) reduction in number of
receiving waters with potential human health cancer risks, d)
reductions in number of receiving waters with potential to cause non-
cancer human health effects, e) reduction in nutrient impacts, f)
reduction in other environmental impacts, and g) unquantified
environmental improvements.
A. Improvements in Surface Water and Ground Water Quality
The reduced pollutant loadings associated with the preferred
options (Option 3a, Option 3b, Option 3, and Option 4a) would lead to
reduced contamination levels in surface waters and sediments. EPA
estimated that reduced pollutant loadings to surface waters associated
with Option 3a would significantly improve water quality by reducing
metal concentrations by up to 33 percent on average within the
immediate receiving waters. Option 3b, Option 3, and Option 4a would
achieve average reductions of up to 36 percent, 48 percent, and 60
percent, respectively. The pollutants with the greatest number of water
quality standard (NRWQC or MCL) exceedances under baseline pollutant
loadings include: total arsenic, total thallium, dissolved cadmium, and
total selenium. EPA determined that 49 percent of the immediate
receiving waters exceeded a water quality standard under baseline
loadings. EPA estimates the number of immediate receiving waters with
aquatic life exceedances, which are driven by dissolved cadmium and
total selenium concentrations, would be reduced by up to 29 percent for
both Option 3a and Option 3b, up to 35 percent for Option 3, and up to
55 percent for Option 4a under the post-compliance pollutant loadings.
EPA also estimates that the number of immediate receiving waters with
human health water quality standards exceedances, primarily driven by
total arsenic and total thallium concentrations, would be reduced by up
to 14 percent for Option 3a, up to 15 percent for Option 3b, up to 18
percent for Option 3, and up to 41 percent for Option 4a.
Selenium was one of the primary pollutants identified in the
literature as causing documented environmental impacts to fish and
wildlife. EPA calculates that total selenium receiving water
concentrations would be reduced by 33 percent on average under Option
3a, 36 percent on average under Option 3b, 48 percent on average under
Option 3, and 60 percent on average under Option 4a. This would reduce
the number of immediate receiving waters exceeding the freshwater
chronic criteria for selenium by 38 percent under Option 3a, 40 percent
under Option 3b, 55 percent under Option 3, and 67 percent under Option
4a. EPA estimates that up to 3,643 river miles (Option 3a), 3,862 river
miles (Option 3b), 4,830 river miles (Option 3), and 6,633 river miles
(Option 4a) downstream from steam electric discharges would no longer
exceed aquatic life and human health NRWQC or MCL standards under the
post-compliance pollutant loadings.
The preferred options would both reduce ground water contamination
levels and improve the availability of ground water resources by
reducing the future leaching of pollutants from steam electric
impoundments to groundwater aquifers. Section XIV provides additional
details on the benefits analysis of these ground water improvements.
B. Reduced Impacts to Wildlife
EPA calculates that the number of immediate receiving waterbodies
with potential impacts to wildlife would be
[[Page 34507]]
reduced by up to 23 percent under Option 3a, up to 24 percent under
Option 3b, up to 30 percent under Option 3, and up to 51 percent under
Option 4a. EPA developed the receiving waters wildlife model to
quantify the impacts to wildlife that consume fish exposed to steam
electric discharges. EPA selected minks and eagles as representative
indicator species to evaluate the impact discharges of the evaluated
wastestreams posed to birds and mammals that consume fish. EPA selected
minks and eagles based on their national population distribution and
the fact that a majority of their diet is comprised of fish. EPA
modeled fish tissue concentrations for the immediate and downstream
receiving waters and compared those concentrations to no effect hazard
concentrations (NEHC) benchmarks developed by the U.S. Geological
Survey (USGS) that indicate potential impacts to piscivorous (i.e.,
fish eating) wildlife. The NEHC benchmarks developed by the USGS are
based on ``no observed adverse effect levels'' (NOAELs), which were
derived from adult dietary exposure or tissue concentration studies and
based primarily on reproductive endpoints.
EPA determined that combustion wastewater discharges into lakes
pose the greatest risk to piscivorous wildlife, with approximately 78
percent of lakes compared to 39 percent of rivers exceeding a NEHC
benchmark for minks or eagles under baseline pollutant loadings.
Mercury and selenium, and to a lesser extent cadmium and zinc, were the
primary pollutants with greatest number of receiving waters with
wildlife NEHC benchmark exceedances. EPA estimates that the preferred
options would reduce the number of immediate receiving waters exceeding
the mercury NEHC for minks and eagles by up to 24 percent under Option
3a, up to 26 percent under Option 3b, up to 33 percent under Option 3,
and up to 52 percent under Option 4a. For selenium, EPA estimates that
the number of immediate receiving waters exceeding the selenium NEHC
would be reduced by up to 29 percent under Option 3a, up to 31 percent
under Option 3b, up to 42 percent under Option 3, and up to 56 percent
under Option 4a. This indicates that the preferred options would reduce
the bioaccumulative impact of the evaluated wastestreams in the broader
ecosystem. EPA estimates that up to 4,135 river miles (Option 3a), up
to 4,360 river miles (Option 3b), up to 5,300 river miles (Option 3),
and up to 8,206 river miles (Option 4a) downstream from steam electric
discharges would no longer exceed a NEHC benchmark for minks or eagles
under the post-compliance pollutant loadings.
In addition, EPA estimates that the upgrades to water quality
(i.e., reductions in aquatic life NRWQC exceedances) discussed above
would improve aquatic and wildlife habitats in the immediate and
downstream receiving waters from steam electric discharges. EPA
determined that these water quality and habitat improvements would
enhance efforts to protect threatened and endangered species. EPA
identified eight species with a high vulnerability to changes in water
quality whose recovery would be expected to be enhanced by the post-
compliance pollutant loading reductions associated with the preferred
options.
C. Reduced Human Health Cancer Risk
EPA estimates that reductions in arsenic loadings from the
preferred options would result in a reduction in potential cancer risks
to humans that consume fish exposed to discharges of the evaluated
wastestreams. The human health model calculates the potential cancer
risk for select age groups and consumption categories (i.e., child and
adult recreational fishers and child and adult subsistence fishers)
based on assumptions of arsenic bioaccumulation in fish exposed to
discharges of the evaluated wastestreams. Under baseline pollutant
loadings, EPA determined that up to 9 percent of immediate receiving
waters contain fish contaminated with inorganic arsenic that would
present cancer risks above the 1-in-a-million threshold for one or more
of the cohorts evaluated. EPA determined that, depending on the cohort,
immediate receiving waters with cancer risks above the 1-in-a-million
threshold would be reduced by up to 40 percent (Option 3a), up to 60
percent (Option 3b and Option 3), and up to 80 percent (Option 4a)
under post-compliance loadings. In addition, EPA estimates that up to
266 river miles, depending on the cohort, downstream from the steam
electric discharges contain fish contaminated with inorganic arsenic
that would present cancer risks above the 1-in-a-million threshold.
Under the post-compliance pollutant loadings associated with the
preferred options, EPA estimates that up to 111 river miles (Option
3a), up to 116 river miles (Option 3b), up to 133 river miles (Option
3), and up to 169 river miles (Option 4a) downstream from steam
electric discharges would no longer contain fish contaminated with
inorganic arsenic that would present cancer risks above the 1-in-a-
million threshold for adult subsistence fishers.
D. Reduced Threat of Non-Cancer Human Health Effects
Exposure to metals poses risk of systemic and other effects to
humans, including effects on the circulatory, respiratory, or digestive
systems and neurological and developmental effects. The preferred
options are estimated to reduce the number of receiving waters with
potential to cause non-cancer health effects in humans who consume fish
exposed to discharges of the evaluated wastestreams. The human health
model calculates the number of immediate receiving waters with the
potential to cause non-cancer health effects in select age groups and
consumption categories (i.e., child and adult recreational fishers and
child and adult subsistence fishers) based on assumptions of metal
bioaccumulation in fish exposed to discharges of the evaluated
wastestreams. Depending on the cohort, EPA calculates that exceedances
of non-cancer reference doses from the consumption of fish would
decrease in up to 19 percent of surface waters (Option 3a), up to 21
percent of surface waters (Option 3b), up to 26 percent of surface
waters (Option 3), and up to 53 percent of surface waters (Option 4a)
immediately receiving discharges of the evaluated wastestreams. Non-
cancer risks are driven by mercury (as methylmercury), total thallium,
and total selenium, and to a lesser degree, total cadmium pollutant
loadings. Under baseline pollutant loadings, the average daily dose
from the consumption of fish in up to 65 percent of immediate receiving
waters exceeds the non-cancer reference dose for mercury depending on
the cohort. Under post-compliance loadings, exceedances of the non-
cancer mercury reference dose would decrease in up to 21 percent
(Option 3a), up to 22 percent (Option 3b), up to 29 percent (Option 3),
and up to 49 percent (Option 4a) of immediate receiving waters,
depending on the cohort. In addition, exceedances of total thallium and
total selenium non-cancer reference doses would decrease in up to 14
and 50 percent of immediate receiving waters (Option 3a and Option 3b),
up to 18 and 69 percent of immediate receiving waters (Option 3), and
up to 43 and 77 percent of immediate receiving waters (Option 4a),
respectively. EPA also estimates that, under the post-compliance
pollutant loadings, exceedances of non-cancer reference doses from the
consumption of fish would decrease in up to 4,084 river miles
downstream (Option 3a), up to 4,316 river miles downstream (Option 3b),
up to 5,400 river miles downstream
[[Page 34508]]
(Option 3), and up to 8,087 river miles downstream (Option 4a) for one
or more of the cohorts.
In addition to the assessment of non-cancer reference dose
exceedances described above, EPA also evaluated the adverse health
effects to children who consume fish contaminated with lead from
combustion wastewater. EPA estimated the reduction in lead exposure to
pre-school children via consumption of contaminated fish tissue and
determined that the preferred options would reduce the associated
intelligence quotient (IQ) loss among children who live in recreational
angler and subsistence fisher households. The preferred options would
also be expected to reduce the incidence of other health effects
associated with lead exposure among children, including slowed or
decayed growth, delinquent and anti-social behavior, metabolic effects,
impaired hemesynthesis, anemia, impaired hearing, and cancer. The
preferred options would also reduce the IQ loss among children exposed
in-utero to mercury from maternal fish consumption in populations
exposed to immediate and downstream receiving waters from steam
electric discharges. Section XIV.B.1.a provides additional details on
the benefits analysis of these reduced IQ losses.
EPA expects that the preferred options would result in additional
non-cancer human health effects beyond those described above, including
reduced health hazards due to exposure to contaminants in waters that
are used for recreational purposes (e.g., swimming).
E. Reduced Nutrient Impacts
The primary concern with nutrients in steam electric discharges is
the potential for adverse nutrient impacts to occur in water-bodies
that receive discharges from multiple plants. Nine percent of surface
waters receiving steam electric wastewater discharges are impaired for
nutrients. While the current concentration of nitrogen present in steam
electric discharges from any individual power plant is relatively low,
the total nitrogen loadings from a single plant can be significant due
to large wastewater discharge flow rates. Total nutrient loadings from
multiple power plants is especially a concern on water bodies that are
nutrient impaired or in watersheds that contribute to downstream
nutrient problems.
Excessive nutrient loadings to receiving waters can significantly
affect the ecological stability of freshwater and saltwater aquatic
systems. Nutrient over-enrichment of surface waters can stimulate
excessive plant growth that can obstruct sunlight penetration and
increase turbidity, which can result in the death of bottom-dwelling
aquatic plants. Higher nutrient loadings from steam electric discharges
could result in the eutrophication of waters and the formation of
hazardous algal blooms. An additional concern with nutrients in steam
electric discharges is the potential for the total nitrogen loadings
from plants to increase in the future as air pollution limits become
stricter and the use of air pollution controls increases.
EPA projects that the preferred options would reduce total nutrient
loadings by 39 percent (Option 3a), by 41 percent (Option 3b), by 53
percent (Option 3), and by 66 percent (Option 4a) and improve overall
water quality. EPA used the SPARROW (SPAtially Referenced Regressions
On Watershed attributes) model to calculate immediate receiving water
concentrations under baseline conditions and under five of the
regulatory options discussed in Section VIII of this preamble (Options
1, 2, 3, 4, and 5) to analyze benefits related to improvements in water
quality. EPA used these concentrations to develop sub-indices for a
water quality index (WQI), a value that translates water quality
measurements, gathered for multiple parameters that represent various
aspects of water quality, into a single numerical indicator. Section
XIV provides additional details on the water quality benefits analysis
of nutrient reductions.
F. Unquantified Environmental and Human Health Improvements
The above environmental assessment focused on the quantification of
environmental improvements within rivers and lakes from post-compliance
pollutant loading reductions for toxic metals and excessive nutrients.
While extensive, the environmental improvements quantified do not
encompass the full range of improvements anticipated to result from the
preferred options simply because some of the improvements have no
method for measuring a quantifiable or monetizable improvement. EPA
expects post-compliance pollutant loading reductions from the preferred
options to result in much greater improvements to wildlife, human
health and environmental health by reducing the:
Loadings of bioaccumulative metals to the broader
ecosystem resulting in the reduction of long-term exposures and
sublethal ecological effects;
Sublethal chronic effects of toxic metals on aquatic life
not captured by the NRWQC;
Impacts to aquatic and aquatic-dependant wildlife
population diversity and community structures;
Exposure of wildlife to pollutants through direct contact
with combustion residuals impoundments and constructed wetlands built
as treatment systems at steam electric power plants;
Adverse health effects in adults resulting from exposure
to lead from consumption of contaminated fish tissue; and
Potential for the formation of hazardous algal blooms.
Data limitations prevented appropriately modeling the scale and
complexity of the ecosystem processes potentially impacted by
combustion wastewater, resulting in the inability to quantify the
improvements listed. However, documented case studies in the literature
reinforce that these impacts are common in the environments surrounding
steam electric power plants and fully support the conclusion that
reducing pollutant loadings will improve overall environmental, human
health and wildlife health.
Although the Environmental Assessment quantifies impacts to
wildlife that consume fish contaminated with metals from combustion
wastewater, it does not capture the full range of exposure pathways
through which bioaccumulative metals can enter the surrounding food
web. Wildlife can encounter toxic bioaccumulative metals from
discharges of the evaluated wastestreams from a variety of exposure
pathways such as direct exposure, drinking water, consumption of
contaminated vegetation, and consumption of contaminated prey other
than fish. Therefore, the quantified improvements underestimate the
complete loadings of bioaccumulative metals that can impact wildlife in
the ecosystem. EPA anticipates that the post-compliance pollutant
loading reductions associated with the preferred options would lower
the total amount of toxic bioaccumulative metals entering the food web
near steam electric power plants.
EPA also expects the estimated reduction in pollutant loadings to
lower the occurrence of sublethal effects associated with many of the
pollutants in combustion wastewater that may not be captured by
comparisons with NRWQC for aquatic life. Chronic effects such as
changes in metabolic rates, decreased growth rates, changes in
morphology (e.g., fin erosion, oral deformities), and behavior (e.g.,
swimming ability, ability to catch prey, ability to escape from
predators) that
[[Page 34509]]
can negatively affect long-term survival, are well documented in the
literature in environments near steam electric power plants. Reductions
in organism survival rates from the chronic effects such as
abnormalities can alter interspecies relationships (e.g., declines in
the abundance or quality of prey) and prolong ecosystem recovery.
However, these effects were not quantified in the environmental
assessment and improvements to wildlife health and survival from the
preferred options are, therefore, underestimated. EPA was unable to
quantify changes to aquatic and wildlife population diversity and
community dynamics; however, population effects (i.e., decline in
number and type of organisms present) attributed to exposure to
combustion wastewater are well documented in the literature. Changes in
aquatic populations can alter the structure of aquatic communities and
cause cascading effects within the food web that result in long-term
impacts to ecosystem dynamics. EPA expects that post-compliance
pollutant loading reductions associated with the preferred options
would lower the stressors that can cause alterations in population and
community dynamics and improve the overall function of ecosystems
surrounding steam electric power plants, as well as help resolve issues
faced in other national ecosystem protection programs such as the Great
Lakes program, the National Estuaries program and the 303(d) impaired
waters program.
EPA anticipates that the expected post-compliance pollutant loading
reductions associated with the preferred options would also decrease
the environmental impacts to wildlife exposed to pollutants through
direct contact with combustion residuals impoundments and constructed
wetlands at steam electric power plants. Documented case studies
demonstrate that wildlife living in close proximity to combustion
residuals impoundments exhibit elevated levels of arsenic, cadmium,
chromium, lead, mercury, selenium, strontium, and vanadium. Multiple
studies have linked attractive nuisance areas (contaminated areas at a
steam electric power plant, such as combustion wastewater surface
impoundments, that are attractive to wildlife (place for nesting)) to
diminished reproductive success. EPA expects that the post-compliance
pollutant loadings would decrease the exposure of wildlife populations
to toxic pollutants and reduce the risks for impacts on reproductive
success.
G. Other Secondary Improvements
EPA anticipates that other secondary, or ancillary, improvements
would occur to other resources that are associated directly or
indirectly as a result of the preferred options. These would include
aesthetic and recreational improvements, reduced economic impacts such
as clean up and treatment costs in response to contamination or
impoundment failures, reduced injury associated with pond failures,
reduced water usage and reduced air emissions. Section XIV provides
additional details on the benefits of these other secondary
improvements.
XIV. Benefit Analysis
This section summarizes EPA's estimates of the national
environmental benefits expected to result from reduction in pollutant
discharges described in Section IX and the resultant environmental
effects summarized in Section XIII. The Benefit and Cost Analysis for
the Proposed Effluent Limitations Guidelines and Standards for the
Steam Electric Power Generating Point Source Category (BCA) report
provides additional details on benefits methodologies and analysis,
including uncertainties and limitations.
A. Categories of Benefits Analyzed
Table XIV-1 summarizes benefit categories associated with this
proposed rule and notes which categories EPA was able to quantify and
monetize. Analyzed benefits fall within six broad categories: human
health benefits, ecological conditions and recreational use benefits
from surface water quality improvements, market and productivity
benefits, air-related benefits, groundwater quality benefits, and water
withdrawal benefits. Within these broad categories, EPA was able to
assess benefits with varying degrees of completeness and rigor. Where
possible, EPA quantified the expected effects and estimated monetary
values. However, data limitations and gaps in the understanding of how
society values certain water quality changes prevent EPA from
quantifying and/or monetizing some benefit categories.
Table XIV-1--Benefit Categories Associated With Proposed ELGs
----------------------------------------------------------------------------------------------------------------
Neither
Benefit category Quantified and Quantified but quantified nor
monetized not monetized monetized
----------------------------------------------------------------------------------------------------------------
1. Human Health Benefits from Surface Water Quality Improvements
----------------------------------------------------------------------------------------------------------------
Reduced incidence of cancer from arsenic exposure via X ................. .................
fish consumption......................................
Reduced non-cancer adverse health effects (e.g., ................. X .................
reproductive, immunological, neurological,
circulatory, or respiratory toxicity) due to exposure
to arsenic from fish consumption......................
Reduced IQ loss in children from lead exposure via fish X ................. .................
consumption...........................................
Reduced need for specialized education for children X ................. .................
from lead exposure via fish consumption...............
Reduced adverse health effects in adults from exposure ................. ................. X
to lead from fish consumption.........................
Reduced in-utero mercury exposure via maternal fish X ................. .................
consumption...........................................
Reduced health hazards from exposure to pollutants in ................. ................. X
waters used recreationally (e.g., swimming)...........
----------------------------------------------------------------------------------------------------------------
2. Ecological Conditions and Recreational Use Benefits from Surface Water Quality Improvements
----------------------------------------------------------------------------------------------------------------
Benefits from improvements in surface water quality, X ................. .................
including: improved aquatic and wildlife habitat;
enhanced water-based recreation, including fishing,
swimming, boating, and near-water activities;
increased aesthetic benefits, such as enhancement of
adjoining site amenities (e.g., residing, working,
traveling, and owning property near the water\a\; and
non-use value (i.e., existence, option, and bequest
value from improved ecosystem health)\a\..............
[[Page 34510]]
Benefits from improved protection of threatened and X ................. .................
endangered species....................................
Reduced sediment contamination......................... ................. ................. X
----------------------------------------------------------------------------------------------------------------
3. Groundwater Quality Benefits
----------------------------------------------------------------------------------------------------------------
Reduced groundwater contamination...................... X ................. .................
----------------------------------------------------------------------------------------------------------------
4. Market and Productivity Benefits
----------------------------------------------------------------------------------------------------------------
Reduced impoundment failures (monetized benefits X ................. .................
include avoided cleanup costs and environmental
damages; non-quantified benefits include avoided
injury)...............................................
Reduced water treatment costs for municipal drinking ................. ................. X
water, irrigation water, and industrial process.......
Improved commercial fisheries yields................... ................. ................. X
Increased tourism and participation in water-based ................. ................. X
recreation............................................
Increased property values from water quality ................. ................. X
improvements..........................................
----------------------------------------------------------------------------------------------------------------
5. Air-Related Benefits
----------------------------------------------------------------------------------------------------------------
Reduced mortality from exposure to NOX, SO2 and X ................. .................
particulate matter (PM2.5)............................
Avoided climate change impacts from CO2 emissions...... X ................. .................
----------------------------------------------------------------------------------------------------------------
6. Benefits from Reduced Water Withdrawals
----------------------------------------------------------------------------------------------------------------
Increased availability of groundwater resources........ X ................. .................
----------------------------------------------------------------------------------------------------------------
a. These values are implicit in the total willingness to pay (WTP) for water quality improvements.
The following section discusses EPA's analysis of the benefits that
the Agency was able to quantify and monetize (identified in the second
column of Table XIV-1). The proposed rule would also result in
additional benefits that the Agency was not able to monetize. See the
Benefits and Cost Analysis Document for information about these non-
monetized benefits.
EPA estimated benefits for five of the eight regulatory options
discussed in this preamble (Options 1, 2, 3, 4, and 5). EPA did not
estimate the benefits of Options 3a, 3b and 4a. However, EPA used its
understanding of the wastestreams and treatment technologies for these
options, along with projections of pollutant reductions for all eight
options, to estimate total monetized benefits for Options 3a, 3b, and
4a. However, EPA is less confident that this approach would yield
reasonable estimates if applied to the individual categories of
benefits (water quality, air emissions, avoided impoundment failure
cleanup costs, etc) and so has not done so. For these more granular
benefits categories, estimates are provided only for Options 1, 2, 3,
4, and 5. Again, these can serve as upper and lower bounds for the
individual categories of benefits of Options 3a, 3b, and 4a.
Specifically, monetized benefits for Options 3a and 3b are likely to be
between those for Options 2 and 3. Similarly, monetized benefits for
Option 4a are likely to be between those for Options 3 and 4.
B. Quantification and Monetization of Benefits
1. Human Health Benefits From Surface Water Quality Improvements
Reduced pollutant discharges from steam electric plants generate
human health benefits in a number of ways. Pollutants commonly
discharged in Steam Electric plant wastewater streams include
conventional and toxic pollutants such as arsenic, cadmium, chromium,
copper, lead, mercury, selenium, and zinc (steam electric pollutants).
Exposure to these pollutants via consumption of fish from affected
waterways can cause a wide variety of adverse health effects, including
cancer, kidney damage, nervous system damage, fatigue, irritability,
liver damage, circulatory damage, vomiting, diarrhea, brain damage, IQ
loss, and many others. Because the proposed ELGs would reduce
discharges of steam electric pollutants into receiving waterways and
downstream areas, they are likely to result in decreased incidences of
associated illnesses.
Due to data limitations and uncertainties, EPA is able to monetize
only a small subset of the health benefits associated with decreased
pollutant discharges from steam electric plants. EPA analyzed the
following measures of human health-related benefits: reduced cancer
risk due to arsenic exposure from fish consumption, reduced lead-
related IQ loss in children from fish consumption, and reduced mercury-
related IQ loss in children exposed in-utero due to maternal fish
consumption. EPA monetized these human health benefits by estimating
the change in the expected number of individuals experiencing adverse
human health effects in the populations exposed to steam electric
discharges under various regulatory options and valuing these changes
using a variety of nonmarket approaches (e.g., cost of illness).
a. Monetized Human Health Benefits
EPA quantified and monetized the following four categories of human
health benefits:
Benefits from Reduced Incidence of Cancer from Arsenic
Exposure via Fish Consumption. EPA assessed changes in the incidence of
cancer cases from consumption of arsenic in the tissue of fish caught
in waters affected by steam electric plant discharges. For the baseline
and each regulatory option, EPA estimated cancer risk from the
consumption of arsenic-contaminated fish for recreational and
subsistence anglers and their families. EPA used data on the
populations living within 100 miles of affected waterbodies, state-
specific average fishing rates, presence of fish consumption
advisories, the availability of substitute fishing
[[Page 34511]]
locations, and average household size to estimate the exposed
population for each steam electric facility. To identify the change in
number of cancer cases caused by arsenic in this population, EPA used a
cancer slope factor (CSF) from EPA's Integrated Risk Information System
(IRIS) of 1.5 per mg/kg-day and different fish consumption rates for
recreational and subsistence anglers and age cohorts. The Agency valued
changes in incidence of cancer cases using a value of a statistical
life (VSL) of $8.0 million (2010$), with projections adjusted to
account for income growth. This estimate does not include estimates of
willingness to pay (WTP) to avoid illness prior to death.
Benefits from Reduced IQ Loss in Children from Lead
Exposure via Fish Consumption. Children's rapid rate of development
makes them more susceptible to neurobehavioral effects from lead
exposure. The neurobehavioral effects on children from lead exposure
include hyperactivity, behavioral and attention difficulties, delayed
mental development, and motor and perceptual skill deficits. EPA
assessed benefits of reduced lead exposure from consumption of
contaminated fish tissue and the associated IQ loss among children aged
0 to 7. EPA estimated blood-lead levels using EPA's Integrated
Exposure, Uptake, and Biokinetic (IEUBK) Model based on daily lead
ingestion rates among children from birth to the seventh birthday.
Based on blood lead concentrations for children in recreational and
subsistence anglers' families, EPA assessed neurobehavioral effects on
children using an established dose response relationship between blood
lead concentrations and IQ loss. Avoided neurological and cognitive
damages are expressed as an increase in overall IQ points in the
exposed population. EPA monetized the estimated changes in IQ scores
based on the impact of additional IQ points on individuals' future
earnings. EPA assumed that each IQ point is worth between $1,156
(following Schwarz (1994) and discounting future earnings at 7 percent)
and $13,651 (following Salkever (1995) and discounting future earnings
at 3 percent).
Benefits from Reduced Need for Specialized Education for
Children from Lead Exposure via Fish Consumption. EPA also quantified
the reduced incidences of especially high blood-lead levels (above 20
mg/dL) and low IQ scores (<70, or two standard deviations below the
mean), and monetized the avoided costs associated with compensatory
education that an individual would otherwise need. For this analysis,
EPA used the IEUBK model to estimate how many children in the exposed
population would have blood lead concentrations above 20 mg/dL, and
assumed that 20 percent of those children would have IQ scores below
70. Based on education cost data from the United States Department of
Education, EPA assumed that the incremental cost of special education
for these individuals and ages 7 through 18 would be approximately
$157,000 per child at 3 percent discount rate, and $125,500 per child
at 7 percent discount rate.
Benefits of Reduced In-utero Mercury Exposure via Maternal
Fish Consumption. Mercury is a highly toxic pollutant that presents
serious health risks to adults and children, even in very small doses.
Health effects can include damage to the brain, kidneys, heart, and
especially nervous system. These impacts are particularly harmful for
children, who can experience profound and permanent developmental and
neurological delays as a result of exposure in-utero. EPA estimated the
IQ-related benefits associated with reduced in-utero mercury exposure
from maternal fish consumption in exposed populations. EPA used data on
the populations living within 100 miles of affected waterbodies, state-
specific average fishing rates, presence of fish consumption
advisories, the availability of substitute fishing locations, average
household size, the number of women of childbearing age, and state-
specific birth rates to estimate the number of births in the exposed
population. Based on a dose-response function developed by Axelrad et
al. (2007), EPA assigned a 0.18 point IQ loss for each 1 ppm increase
in maternal hair mercury. To translate the daily mercury ingestion rate
by women of childbearing age in the exposed populations to hair mercury
concentrations, EPA used a conversion rate derived by Swartout and Rice
(2000). Including decreased lifetime earnings and avoided education
costs, EPA assumed that the value of an IQ point is between $1,156 and
$13,651 over the life of each individual.
Table XIV-2 summarizes monetized human health benefits associated
with five of the eight regulatory options considered in this proposed
rule using 3 percent and 7 percent discount rates. As mentioned above,
EPA did not monetize the human health benefits associated with Options
3a, 3b and 4a. EPA expects the benefits of Option 4a to be between
those of Options 3 and 4.
Table XIV-2--Annualized Human Health Benefits
[million 2010$] c
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Human health benefit category Option 1 Option 2 Option 3 Option 4 Option 5
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
3% Discount Rate
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Benefits from Reduced Incidence The Agency first estimated annual household WTP values for
a given reach and year using the meta-analysis regression. WTP values
are a function of (1) reach-specific baseline and change in water
quality values in a given year and (2) median household income values
estimated for a given state or buffer zone in that year. For this
analysis, two benefit functions were used for each reach in a given
year; one for households that may have user values (households located
within 100 miles of the reach) and one for nonuser households
(households located with the same state as the reach, but outside the
100-mile buffer).
To estimate total WTP values, the Agency multiplied annual
household WTP values by the percent of total reach miles within the
state or buffer and the total number of households within the state or
buffer for a given year.
EPA then discounted total WTP values to 2014, the expected
[[Page 34514]]
promulgation year of the rule, and annualized them using a 3 and 7
percent discount rate.
A challenge for meta-analysis is developing a framework that both
controls for differences in studies and can be used for meaningfully
predicting benefits associated with regulatory options. In earlier
benefits estimation for effluent guidelines, EPA often relied on the
Carson and Mitchell (1993) water quality values. These values come from
a survey that was one of the first major stated preference efforts,
fielded in the early 1980s. The study reported values for all of the
nation's waters, using the same WQI that is used in the meta-analysis.
When EPA used the Carson and Mitchell values, the Agency was able to
tailor its benefits estimates to its regulations in two important
dimensions: the level of water quality improvement, and the percent of
the nation's waters being improved. EPA is basing this benefits
analysis on the meta-analysis because stated preference methodology and
practices have advanced considerably since the Carson and Mitchell
study (although methodological issues continue to be debated in the
stated preference literature), more studies have been conducted, and
changes in individuals' preferences and income may well result in
changing water quality values.
A trade-off, however, in using the meta-analysis is the difficulty
in representing the percent of the nation's waters that are being
improved, in addition to combining the results of studies encompassing
a variety of water quality improvements, geographic scales, and
resource characteristics that has led to both expected results and
results that are counterintuitive. To provide perspective on these
different approaches to measure water quality improvement benefits, EPA
is also reporting the water quality values obtained by applying the
Carson and Mitchell values. In 2011 dollars, using a 3 percent discount
rate, these values are: for Option 1, $0.5 million; for Option 2, $2.9
million; for Option 3, $4.5 million; for Option 4, $12.9 million; and
for Option 5, $12.7 million. EPA requests comment on its reliance on
the meta-analysis values rather than the Carson and Mitchell values (or
some other values) as the basis for estimating water quality benefits
of the proposed rule. Commenters should address methodological
strengths and weaknesses of any suggested approach, and explain the
basis for their recommendation.
b. Benefits to Threatened and Endangered (T&E) Species
To assess the potential for impacts on threatened and endangered
(T&E) species (both aquatic and terrestrial), EPA constructed a
database of waterbodies currently exceeding wildlife-based AWQC but
expected to have no wildlife AWQC exceedances as a result of the
proposed ELGs. EPA then assessed the overlap between this geographic
database and the known locations of approximately 530 T&E species. Once
species overlapping waterbodies of interest were identified, EPA
examined their life history traits to categorize species by the
potential for population impacts likely to occur as a result of changes
in water quality. T&E species with high probability of life-history
effects were further screened to identify those species for which water
quality was identified as a factor for listing under the Endangered
Species Act (ESA) or as a limiting factor within species recovery
plans. Because of this analysis, EPA identified seven fish species and
one dragonfly species that may experience changes in population growth
rates as a result of the proposed ELGs. EPA did not identify data
sufficient to explicitly model the effects of changes in water quality
on population growth rates for these species. Therefore, to estimate
total population increases resulting from the proposed ELGs, EPA
assumed minimal increases in population size of 0.5, 1, or 1.5 percent.
To estimate monetary benefits to T&E species, EPA weighted these
population growth estimates by the percent of reaches used by T&E
species that are expected to meet wildlife-based AWQC because of the
proposed ELGs.
The T&E species expected to benefit from the rule include two
species of sturgeon and five species of small minnows. All of these
species have nonuse values including existence, bequest, altruistic,
and ecological service values apart from human uses or motives.
To estimate the potential economic values of increased T&E species
populations affected by the proposed ELGs, EPA used a benefit function
transfer approach based on a meta-analysis of 31 stated preference
studies eliciting WTP for these changes (Richardson and Loomis 2009).
This meta-analysis is based on studies conducted in the United States
that valued threatened, rare, or endangered fish, bird, reptile, or
mammal species. Because the underlying meta-data does not include
insect valuation studies, EPA was unable to monetize any benefits for
potential population increases of Hine's Emerald Dragonfly due to the
proposed rule. For each state containing T&E species estimated to show
population growth because of the proposed ELGs, EPA calculated benefits
using the weighted population growth assumptions under each analytic
scenario (regulatory option and population increase assumption). For
states with more than one T&E species estimated to see population
growth, EPA only monetized the value for the species projected to see
the greatest proportional population increase. Because population
growth was calculated at the state level, EPA was unable to calculate
benefits based on when each steam electric plant is assumed to install
control technologies to comply with the proposed ELGs. EPA therefore
assumed that benefits begin accruing in 2019 for all states because
this is the midpoint of the compliance period used in other cost and
benefit analyses and thus provides a reasonable assumption.
There may be some overlap between WTP estimates for T&E species and
the WTP estimates for improvements in water quality; however, the
magnitude of this overlap is likely to be minimal because none of the
studies in EPA's meta-analysis of WTP for water quality improvements
specifically mentioned or otherwise prompted respondents to include
benefits to T&E species populations.
Table XIV-3 summarizes the results of EPA's analysis of benefits
from improved ecological conditions and recreational uses for five of
the eight regulatory options. EPA did not estimate the benefits of
Options 3a, 3b and 4a. As for the other benefit categories, however,
the Agency expects the benefits of Option 4a to be between those of
Options 3 and 4 (i.e., between $59.9 million and $116.1 million
annually, at 3 percent discount rate).
[[Page 34515]]
Table XIV-3--Annualized Ecological Conditions and Recreational Uses Benefits
[Million 2010$] \e\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Benefit category Option 1 Option 2 Option 3 Option 4 Option 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Improved Surface Water Quality $8.3.................. $38.0................. $49.9................. $82.8................. $81.9
\a\. ($2.0 to $22.4)....... ($7.1 to $107.1)...... ($10.2 to $137.6)..... ($19.6 to $215.8)..... ($19.3 to $214.1)
-----------------------------------------------------------------------------------------------------------------------
Benefits to E&T Species \b\..... $7.0.................. $7.0.................. $10.0................. $33.3................. $33.3
($3.9 to $10.0)....... ($3.9 to $10.0)....... ($5.5 to $14.2)....... ($18.2 to $47.3)...... ($18.2 to $47.3)
-----------------------------------------------------------------------------------------------------------------------
Total Ecological and $15.3................. $45.0................. $59.9................. $116.1................ $115.2
Recreational Uses Benefits ($5.8 to $32.4)....... ($11.0 to $117.7)..... ($15.7 to $151.8)..... ($37.8 to $263.1)..... ($37.5 to $261.4)
\d\.
--------------------------------------------------------------------------------------------------------------------------------------------------------
7% Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Improved Surface Water Quality $6.9.................. $31.7................. $41.7................. $69.2................. $68.5
\a\. ($1.6 to $18.7)....... ($6.0 to $48.3)....... ($8.5 to $115.0)...... ($16.4 to $180.3)..... ($16.1 to $178.9)
-----------------------------------------------------------------------------------------------------------------------
Benefits to E&T Species \b\..... $5.9.................. $5.9.................. $8.4.................. $27.8................. $27.8
($3.2 to $8.4)........ ($3.2 to $8.4)........ ($4.6 to $11.9)....... ($15.2 to $39.5)...... ($15.2 to $39.5)
-----------------------------------------------------------------------------------------------------------------------
Total Ecological and $12.8................. $37.6................. $50.1................. $97.0................. $96.2
Recreational Uses Benefits ($4.8 to $27.0)....... ($9.1 to $56.6)....... ($13.1 to $126.9)..... ($31.6 to $219.8)..... ($31.3 to $218.4)
\d\.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values represent partial benefits only for reaches that receive direct discharges from steam electric plants. Range in parenthesis represents the
5th and 95th percentile of the WTP distribution.
\b\ Range in parenthesis provides the low and high bound estimates.
\c\ Range in parenthesis provides the 5th and 95th percentile of the WTP distribution incorporating minimum and maximum flow reduction assumptions.
\d\ Totals may not add up due to independent rounding.
\e\ EPA did not estimate the benefits of Options 3a, 3b and 4a. EPA expects the benefits of Option 4a to be between those of Options 3 and 4.
3. Groundwater Quality Benefits From Reduced Groundwater Contamination
EPA expects that some of the regulatory options will eliminate the
future leaching of steam electric pollutants from steam electric
impoundments to groundwater aquifers. The Agency monetized the
associated benefits to households using private drinking wells in the
vicinity of steam electric plants based on a benefits transfer from
groundwater valuation studies. Specifically, EPA used existing
groundwater valuation studies to derive household WTP estimates for two
categorical improvements in groundwater quality: (1) ``greatly
improved'' and (2) ``improved.''
EPA identified the exposed population as the number of households
using private drinking water wells in the vicinity of steam electric
impoundments. EPA then modeled pollutant concentrations in the affected
aquifers and determined which aquifers exceed maximum contaminant
levels (MCLs) for steam electric pollutants under the baseline. EPA
assumed that if a plant ceases to use impoundments to handle combustion
waste because of the proposed ELGs, these aquifers would improve, with
an average household WTP of $450. For impoundments that continue to
receive combustion wastes but in smaller amounts, EPA assumed that the
plant-specific benefits would be proportional to the reduction in
wastewater flows going to the impoundment, and scaled the benefits
accordingly.
Table XIV-4 summarizes the results of EPA's analysis of the
groundwater benefits. As for other benefit categories, EPA did not
analyze the benefits of Options 3a, 3b and 4a. EPA expects the benefits
of Option 4a to be between those of Options 3 and 4 (i.e., $1.6 million
to $6.5 million annually, at 3 percent discount rate).
Table XIV-4--Annualized Groundwater Quality Benefits
[Million 2010$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Discount rate Option 1 Option 2 Option 3 Option 4 Option 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% Discount Rate.............................................. $0.7 $0.7 $1.6 $6.5 $6.5
7% Discount Rate.............................................. 0.6 0.6 1.4 5.5 5.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 34516]]
4. Market and Productivity Benefits (Benefits From Reduced Impoundment
Failures)
Operational changes prompted by compliance with the proposed ELGs
may cause some plant owners to reduce their reliance on impoundments to
handle their waste. EPA expects these changes to reduce future impacts
from impoundment failures.
To assess the benefits associated with changes in impoundment use,
EPA estimated the costs associated with expected failures for baseline
conditions (assuming no change in operations) and for projected
reductions in the amount of CCR waste managed by impoundments for five
of the eight regulatory options (Options 1, 2, 3, 4, and 5). EPA
performed the calculations for each of the 1,070 impoundments
identified at steam electric plants, and for each year between 2014 and
2040. EPA then calculated benefits as the difference between expected
failure costs for a regulatory option and expected failure costs under
baseline conditions.
To estimate the number of structural failure events that may be
avoided as a result of the proposed ELGs, EPA used data on historical
impoundment failures collected by EPA's Office of Resource Conservation
and Recovery (ORCR) for its Regulatory Impact Analysis for EPA's
Proposed Regulation of Coal Combustion Residues Generated by the
Electric Utility Industry (Proposed CCR Rule; U.S. EPA 2010). Based on
historical data, EPA estimated an average failure rate of 0.58 percent
per impoundment per year and used this average failure rate to
calculate the expected number of failure events in the baseline and
under each of the regulatory options.\86\ EPA also used data on
historical failure events to develop average cleanup, natural resource
damages,\87\ and litigation costs \88\ per event. As detailed in
Chapter 7 of the BCA, EPA used average total costs of $0.06 per gallon
of impoundment capacity to estimate the expected costs of an
impoundment failure.\89\ EPA did not calculate benefits for years 2014
through 2018 because EPA conducted surface impoundment integrity site
assessments in 2009 through 2012 and expects the assessments and the
recommended ``action plan'' improvements to impoundment structures will
prevent all failures for the first five years after improvement are
completed (i.e., 2014 through 2018).
---------------------------------------------------------------------------
\86\ EPA also estimated benefits using a best-fit regression
equation developed based on the historical data that relates the
probability of impoundment failure to impoundment capacity. For
details, see Appendix G of the BCA.
\87\ Natural resource damages do not include cleanup costs (or
legal costs) but include only the resource restoration and
compensation values. For example, in one case, Israel (2006) found
that ``In total, the State's claim was $764 million, $342 million of
which was restoration cost damages, $410 million of which was
compensable value damages, and $12 million of which was assessment
and legal costs.'' For this case, EPA used the sum of $342 million
and $410 million (excluded legal costs) as the value of natural
resource damages.
\88\ For this analysis, litigation costs include the costs
associated with negotiating NRD, determining responsibility among
potentially responsible parties, and litigating details regarding
settlements and remediation. These activities involve services,
whether performed by the complying entity or other parties that EPA
expects would be required in the absence of this regulation in the
event of an impoundment failure. Note that the litigation costs do
not include fines, cleanup costs, damages, or other costs that
constitute transfers or are already accounted for in the other
categories analyzed separately.
\89\ This estimate assumes that each failure results in a
spilled volume equal to 6.45 percent of the impoundment capacity,
based on the average ratio of spill volume to impoundment capacity
for 15 releases for which ORCR obtained both spill volume and
capacity data.
---------------------------------------------------------------------------
Table XIV-5 presents the analysis results. Depending on the
regulatory option, annual benefits range from $62.1 million to $295.1
million (at 3 percent discount rate), with Option 3 having expected
benefits of $114.8 million per year. EPA did not estimate the benefits
of Options 3a, 3b and 4a; the Agency expects the benefits of Option 4a
to be between those of Options 3 and 4 (i.e., $114.8 million to $295.1
million, at 3 percent discount rate). Note that these benefits do not
include the effects of BMPs that may reduce the probability of failures
and therefore would be expected to increase the benefits of the
proposed ELGs. EPA will continue to seek ways to quantify and monetize
BMP-related benefits in analyses for the final rule, should EPA
ultimately include such BMPs as part of the final ELGs.
Table XIV-5--Annualized Benefits of Reduced Impoundment Failures
[Million 2010$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Discount rate Option 1 Option 2 Option 3 Option 4 Option 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% Discount Rate.............................................. $62.1 $62.1 $114.8 $295.1 $295.1
7% Discount Rate.............................................. 52.2 52.2 95.9 245.9 245.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
5. Air-Related Benefits (Reduced Mortality and Avoided Climate Change
Impacts)
The proposed ELGs are expected to affect air pollution through
three main mechanisms: 1) additional auxiliary electricity use by steam
electric plants to operate wastewater treatment, ash handling, and
other systems needed to comply with the new effluent limitations and
standards; 2) additional transportation-related emissions due to the
increased trucking of CCR waste to landfills; and 3) the change in the
profile of electricity generation due to the relatively higher cost to
generate electricity at plants incurring compliance costs for the
proposed ELGs. Changes in the profile of generation can result in lower
or higher air pollutant emissions because of variability in emission
factors for different types of electricity generating units. For this
analysis, the changes in air emissions are based on the change in
dispatch of generation units projected by IPM as a result of overlaying
the costs of the proposed ELGs onto steam electric units production
costs.
In this analysis, EPA estimated the human health and other benefits
resulting from net changes in air emissions of three pollutants:
nitrogen oxides (NOX), sulfur dioxide (SO2), and
carbon dioxide (CO2). NOX and SOX are
known precursors to fine particles (PM2.5), a criteria air
pollutant that has been associated with a variety of adverse health
effects--most notably, premature mortality. CO2 is an
important greenhouse gas that is linked to a wide range of climate
change effects.
EPA used average benefit-per-ton (BPT) estimates to value benefits
of changes in NOX and SO2 emissions, and social
cost of carbon (SCC) estimates to value benefits of changes in
CO2 emissions. Because the analysis relies in part on
estimates of air emissions obtained from IPM, EPA estimated air-related
benefits for Options 3 and 4 only, as these are the two options
analyzed in IPM. Table XIV-6
[[Page 34517]]
summarizes the annualized benefits associated with changes in air
pollutant emissions. Chapter 8 in the BCA report provides the details
of this analysis.
Table XIV-6--Annualized Benefits of Changes in NOX, SO2, and CO2 Air
Emissions
[Million 2010$] \c\
------------------------------------------------------------------------
Discount rate Option 3 Option 4
------------------------------------------------------------------------
3% Discount Rate (for NOX, SO2, and $127.6 $170.5
CO2-related benefits)..............
7% Discount Rate (for NOX, SO2, and 82.3 74.6
CO2-related benefits) a b..........
------------------------------------------------------------------------
\a\ Because SCC values are not available for the 7 percent discount
rate, EPA used the SCC based on a 5 percent discount rate to estimate
values presented for the 7 percent discount rate. EPA uses 5 percent
to discount CO2-related benefits and 7 percent to discount benefits
from changes in NOX and SO2 emissions.
\b\ Air benefits for Option 4 at the 7 percent discount rate are lower
than benefits estimated for Option 3 due to (1) smaller SO2 emissions
reductions projected by IPM for Option 4 than Option 3 in early years
and (2) differences in source- and discount-specific BPT and SCC
values.
\c\ EPA did not estimate the benefits of Options 3a, 1, 2, 3b, 4a and 5.
EPA expects the benefits of Option 4a to be between those of Options 3
and 4.
6. Benefits From Reduced Water Withdrawals (Increased Availability of
Groundwater Resources)
Steam electric plants use water for handling solid waste (e.g., fly
ash, bottom ash) and for operating wet FGD scrubbers. By eliminating or
reducing water used in sluicing operations or prompting the recycling
of water in FGD wastewater treatment systems, the proposed ELGs are
expected to reduce water withdrawals from surface waterbodies and
reduce demand on aquifers, in the case of plants that rely on
groundwater sources.
EPA estimated the benefits of reduced groundwater withdrawals based
on avoided costs of groundwater supply. For each affected facility and
regulatory option, EPA multiplied the reduction in groundwater
withdrawal (in gallons per year) by water costs ranging between $150
and $500 per acre-foot.
Table XIV-7 summarizes the annualized benefits associated with
changes in water use by steam electric plants for five of the eight
options. Chapter 9 in the BCA report provides the details of this
analysis. While EPA did not estimate benefits of Options 3a, 3b and 4a,
the Agency expects the benefits of Option 4a to be between those of
Options 3 and 4.
Table XIV-7--Annualized Monetized Benefits of Reduced Water Withdrawals by Steam Electric Plants
[Million 2010$] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Benefit category Option 1 Option 2 Option 3 Option 4 Option 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Avoided groundwater withdrawals............................... $0.0 $0.0 FGD wastewater: Where an option proposes BAT/NSPS
limitations for FGD wastewater that are not equal to existing BPT
limitations,\92\ EPA is also proposing to require monitoring for
compliance with the proposed effluent limitations and standards prior
to use of the FGD wastewater in any other non-FGD plant process or
commingling of the FGD wastewater with any water or other process
wastewater. This monitoring requirement would not, however, apply prior
to commingling of FGD wastewater with combustion residual leachate
(including legacy leachate) or legacy FGD wastewater that is treated to
achieve pollutant removals equivalent to or greater than achieved by
the BAT/NSPS technology that serves as the basis for the effluent
limitations and standards proposed today.
---------------------------------------------------------------------------
\92\ Similarly applies to PSES and PSNS.
---------------------------------------------------------------------------
For example, many plants currently treat their FGD wastewater and
leachate in onsite surface impoundments. EPA envisions that, under this
proposed Option 3 requirements, some of these plants may choose to
install tank-based FGD wastewater treatment systems for their newly
generated FGD wastewater. Such a plant may chose to discharge the
effluent from its new treatment system directly or may wish to
discharge it to the existing surface impoundment containing legacy
wastewaters. In this case, the plant would be required to demonstrate
compliance with the proposed effluent limitations and standards for the
newly generated FGD wastewater at the effluent from the tank-based FGD
wastewater treatment system, and compliance with the BPT requirements
for the commingled new/legacy FGD wastewater at the point of discharge
from the FGD wastewater impoundment. The same plant may also configure
its system so that the impoundment (which also contains legacy FGD
wastewater)is used for equalization, with the impoundment effluent sent
to the tank-based treatment system. In this case, both the newly
generated FGD wastewater and the legacy FGD wastewater would be treated
by the tank-based treatment system and an appropriate compliance
monitoring point would be the treatment system effluent. Under such a
scenario, commingling of FGD wastewater generated at any date may occur
as long as such combined wastewater meets the effluent limitations or
standards prior to use of the treated commingled new/legacy FGD
wastewater in any other plant process, or combining the FGD wastewater
with any water or other process wastewater.
Ash transport water and FGMC wastewater: EPA is proposing
to specify that whenever ash transport water or flue gas mercury
control wastewater generated from a generating unit that must comply
with the ``zero discharge'' standard is used in any other plant process
or is sent to a treatment system at the plant, the resulting effluent
must comply with the proposed discharge prohibition for the pollutants
in such wastewater.
For example, many plants currently treat their fly ash transport
water in an onsite fly ash impoundment. In this case, under any
proposed ``no discharge'' requirements, EPA envisions that such plants
may convert their fly ash handling to a dry system, and no longer
generate fly ash transport water. In such cases, the plant could
demonstrate compliance with the proposed zero discharge requirement by
showing that no fly ash transport water is generated after the date on
which the new, proposed standards apply and by monitoring for
compliance with the BPT requirements at the discharge from the legacy
fly ash impoundment. Under EPA's proposal, the plant could not
demonstrate compliance with the applicable discharge prohibition by
simply using the fly ash transport water in another plant process that
ultimately discharges because the prohibition on the discharge of
pollutants in ash transport water and FGMC wastewater is also
applicable to the discharge of wastewater from plant processes that use
these wastewaters.
Gasification wastewater: EPA is proposing to require
monitoring for compliance prior to use of the gasification wastewater
in any other plant process or commingling of the gasification
wastewater with water or any other process wastewater. As an example,
EPA envisions gasification plants would show compliance with the
proposed BAT or PSES requirements directly following gasification
wastewater treatment (however, there would be no need to demonstrate
compliance if the gasification wastewater is completely reused within
the gasification process). Combustion Residual Leachate: Under Option 4
and 5, EPA is proposing to require monitoring for compliance prior to
use of leachate in any other plant process or commingling of the
leachate with water or any other process wastewater. This monitoring
requirement would not, however, apply prior to commingling of
combustion residual leachate with FGD wastewater (including legacy FGD
wastewater) or legacy combustion residual leachate that is treated to
achieve pollutant removals equivalent to or greater than that achieved
by the BAT/NSPS technology that serves as the basis for the effluent
limitations and standards proposed today. For example, many plants
currently treat their leachate in onsite surface impoundments. EPA
envisions that, under the proposed requirements, some plants may choose
to install a tank-based leachate treatment system so that the
impoundment (which also contains legacy combustion residual leachate)
is used for equalization, with the impoundment effluent ultimately sent
to the tank-based treatment system. In this case, both the newly
generated leachate and the legacy leachate would
[[Page 34524]]
be treated by the tank-based treatment system and an appropriate
compliance monitoring point would be the treatment system effluent.
Under such a scenario, commingling of combustion residual leachate
generated at any date may occur as long as such combined wastewater
meets the effluent limitations or standards prior to use of the treated
commingled new/legacy leachate in any other plant process, or combining
the leachate with any water or other process wastewater. (If the
combustion residual leachate is commingled with FGD wastewater, the
facility will also have to demonstrate compliance with the applicable
FGD wastewater effluent limitations and standards.) Conversely, under
the proposed requirements, EPA envisions some plants may choose to
install tank-based leachate treatment systems whose effluent is
discharged to the impoundment containing the legacy leachate. In this
case, the plant would be required to demonstrate compliance with the
proposed effluent limitations and standards for the newly generated
combustion residual leachate at the effluent from the tank-based
leachate treatment system and compliance with the BPT requirements for
the commingled new/legacy leachate at the discharge from the
impoundment.
B. Analytical Methods
Section 304(h) of the CWA directs the EPA to promulgate guidelines
establishing test procedures (methods) for the analysis of pollutants.
These methods are used to determine the presence and concentration of
pollutants in wastewater and for compliance monitoring. They are also
used for filing applications for the National Pollutant Discharge
Elimination System (NPDES) permit program under 40 CFR 122.41(j)(4) and
122.21(g)(7), and under 40 CFR 403.7(d) for the pretreatment program.
The EPA has promulgated analytical methods for monitoring discharges to
surface water at 40 CFR part 136 for the pollutants proposed for
regulation in this notice. EPA is providing notice of standard
operating procedures (SOPs) for the analysis of FGD wastewater using
collision cell technology in conjunction with EPA Method 200.8. EPA
Method 200.8 has been promulgated under 40 CFR part 136 and is an
approved method for use in NPDES compliance monitoring. Also, the use
of collision cell technology is an approved modification allowed under
40 CFR part 136.6. See DCN SE03835 and DCN SE03868 for the SOPs and
information on EPA's development of the SOPs.
In addition, as explained in Section VIII, with the exception of
the cases where BAT limitations are equivalent to BPT limitations, EPA
is proposing that compliance with any final limitations or standards
(except pH) based on any of the eight main regulatory options in this
proposed rule reflects results obtained from sufficiently sensitive
analytical methods. Where EPA has approved more than one analytical
method for a pollutant, the Agency expects that permittees would select
methods that are able to quantify the presence of pollutants in a given
discharge at concentrations that are low enough to determine compliance
with effluent limits. For purposes of the proposed anti-circumvention
provisions, a method is ``sufficiently sensitive'' when the sample-
specific quantitation level \93\ for the wastewater matrix being
analyzed is at or below the level of the effluent limit.
---------------------------------------------------------------------------
\93\ For the purposes of this rulemaking, EPA is considering the
following terms related to analytical method sensitivity to be
synonymous: ``quantitation limit,'' ``reporting limit,'' ``level of
quantitation,'' and ``minimum level.''
---------------------------------------------------------------------------
C. Upset and Bypass Provisions
A ``bypass'' is an intentional diversion of wastestreams from any
portion of a treatment facility. An ``upset'' is an exceptional
incident in which there is unintentional and temporary noncompliance
with technology-based permit effluent limitations because of factors
beyond the reasonable control of the permittee. EPA's regulations
concerning bypasses and upsets for direct dischargers are set forth at
40 CFR 122.41(m) and (n) and for indirect dischargers at 40 CFR 403.16
and 403.17.
D. Variances and Modifications
The CWA requires application of effluent limitations established
pursuant to Section 301 or the pretreatment standards of Section 307 to
all direct and indirect dischargers. However, the statute provides for
the modification of these national requirements in a limited number of
circumstances. The Agency has established administrative mechanisms to
provide an opportunity for relief from the application of the national
effluent limitations guidelines for categories of existing sources for
toxic, conventional, and nonconventional pollutants.
1. Fundamentally Different Factors (FDF) Variance
As explained above, the CWA requires application of the effluent
limitations established pursuant to Section 301 or the pretreatment
standards of Section 307 to all direct and indirect dischargers.
However, the statute provides for the modification of these national
requirements in a limited number of circumstances. Moreover, the Agency
has established administrative mechanisms to provide an opportunity for
relief from the application of national effluent limitations guidelines
and pretreatment standards for categories of existing sources for
priority, conventional, and nonconventional pollutants.
EPA may develop, with the concurrence of the state, effluent
limitations or standards different from the otherwise applicable
requirements for an individual existing discharger if it is
fundamentally different with respect to factors considered in
establishing the effluent limitations or standards applicable to the
individual discharger. Such a modification is known as an FDF variance.
EPA, in its initial implementation of the effluent guidelines
program, provided for the FDF modifications in regulations, which were
variances from the BPT effluent limitations, BAT limitations for toxic
and nonconventional pollutants, and BCT limitations for conventional
pollutants for direct dischargers. FDF variances for toxic pollutants
were challenged judicially and ultimately sustained by the Supreme
Court in Chemical Manufacturers Association v. Natural Resources
Defense Council, 470 U.S. 116, 124 (1985).
Subsequently, in the Water Quality Act of 1987, Congress added a
new section to the CWA--Section 301(n). This provision explicitly
authorizes modifications of the otherwise applicable BAT effluent
limitations, if a discharger is fundamentally different with respect to
the factors specified in CWA Section 304 (other than costs) from those
considered by EPA in establishing the effluent limitations. CWA Section
301(n) also defined the conditions under which EPA may establish
alternative requirements. Under Section 301(n), an application for
approval of a FDF variance must be based solely on (1) information
submitted during rulemaking raising the factors that are fundamentally
different or (2) information the applicant did not have an opportunity
to submit. The alternate limitation must be no less stringent than
justified by the difference and must not result in markedly more
adverse non-water quality environmental impacts than the national
limitation.
EPA regulations at 40 CFR part 125, subpart D, authorizing the
regional administrators to establish alternative
[[Page 34525]]
limitations, further detail the substantive criteria used to evaluate
FDF variance requests for direct dischargers. Thus, 40 CFR 125.31(d)
identifies six factors (e.g., volume of process wastewater, age and
size of a discharger's facility) that may be considered in determining
if a discharger is fundamentally different. The Agency must determine
whether, based on one or more of these factors, the discharger in
question is fundamentally different from the dischargers and factors
considered by EPA in developing the nationally applicable effluent
guidelines. The regulation also lists four other factors (e.g.,
inability to install equipment within the time allowed or a
discharger's ability to pay) that may not provide a basis for an FDF
variance. In addition, under 40 CFR 125.31(b)(3), a request for
limitations less stringent than the national limitation may be approved
only if compliance with the national limitations would result in either
(a) a removal cost wholly out of proportion to the removal cost
considered during development of the national limitations, or (b) a
non-water quality environmental impact (including energy requirements)
fundamentally more adverse than the impact considered during
development of the national limits. The legislative history of Section
301(n) underscores the necessity for the FDF variance applicant to
establish eligibility for the variance. EPA's regulations at 40 CFR
125.32(b)(1) impose this burden upon the applicant. The applicant must
show that the factors relating to the discharge controlled by the
applicant's permit that are claimed to be fundamentally different are,
in fact, fundamentally different from those factors considered by EPA
in establishing the applicable guidelines. In practice, very few FDF
variances have been granted for past ELGs. An FDF variance is not
available to a new source subject to NSPS. DuPont v. Train, 430 U.S.
112 (1977).
2. Economic Variances
Section 301(c) of the CWA authorizes a variance from the otherwise
applicable BAT effluent guidelines for nonconventional pollutants due
to economic factors. The request for a variance from effluent
limitations developed from BAT guidelines must normally be filed by the
discharger during the public notice period for the draft permit. Other
filing periods may apply, as specified in 40 CFR 122.21(m)(2). Specific
guidance for this type of variance is provided in ``Draft Guidance for
Application and Review of Section 301(c) Variance Requests,'' dated
August 21, 1984, available on EPA's Web site at http://www.epa.gov/npdes/pubs/OWM0469.pdf.
3. Water Quality Variances
Section 301(g) of the CWA authorizes a variance from BAT effluent
guidelines for certain nonconventional pollutants due to localized
environmental factors. These pollutants include ammonia, chlorine,
color, iron, and total phenols. As this proposed rule would not
establish limitations or standards for any of these pollutants, this
variance would not be applicable to this particular rule.
4. Removal Credits
Section 307(b)(1) of the CWA establishes a discretionary program
for POTWs to grant ``removal credits'' to their indirect dischargers.
Removal credits are a regulatory mechanism by which industrial users
may discharge a pollutant in quantities that exceed what would
otherwise be allowed under an applicable categorical pretreatment
standard because it has been determined that the POTW to which the
industrial user discharges consistently treats the pollutant. EPA has
promulgated removal credit regulations as part of its pretreatment
regulations. See 40 CFR 403.7. These regulations provide that a POTW
may give removal credits if prescribed requirements are met. The POTW
must apply to and receive authorization from the Approval Authority. To
obtain authorization, the POTW must demonstrate consistent removal of
the pollutant for which approval authority is sought. Furthermore, the
POTW must have an approved pretreatment program. Finally, the POTW must
demonstrate that granting removal credits will not cause the POTW to
violate applicable federal, state, or local sewage sludge requirements.
40 CFR 403.7(a)(3).
The United States Court of Appeals for the Third Circuit
interpreted the CWA as requiring EPA to promulgate the comprehensive
sewage sludge regulations pursuant to CWA Section 405(d)(2)(A)(ii)
before any removal credits could be authorized. See NRDC v. EPA, 790
F.2d 289, 292 (3d Cir., 1986); cert. denied., 479 U.S. 1084 (1987).
Congress made this explicit in the Water Quality Act of 1987, which
provided that EPA could not authorize any removal credits until it
issued the sewage sludge use and disposal regulations. On February 19,
1993, EPA promulgated Standards for the Use or Disposal of Sewage
Sludge, which are codified at 40 CFR part 503 (58 FR 9248). EPA
interprets the Court's decision in NRDC v. EPA as only allowing removal
credits for a pollutant if EPA has either regulated the pollutant in
part 503 or established a concentration of the pollutant in sewage
sludge below which public health and the environment are protected when
sewage sludge is used or disposed.
The part 503 sewage sludge regulations allow four options for
sewage sludge disposal: (1) Land application for beneficial use, (2)
placement on a surface disposal unit, (3) firing in a sewage sludge
incinerator, and (4) disposal in a landfill which complies with the
municipal solid waste landfill criteria in 40 CFR part 258. Because
pollutants in sewage sludge are regulated differently depending upon
the use or disposal method selected, under EPA's pretreatment
regulations the availability of a removal credit for a particular
pollutant is linked to the POTW's method of using or disposing of its
sewage sludge. The regulations provide that removal credits may be
potentially available for the following pollutants:
(1) If POTW applies its sewage sludge to the land for beneficial
uses, disposes of it in a surface disposal unit, or incinerates it in a
sewage sludge incinerator, removal credits may be available for the
pollutants for which EPA has established limits in 40 CFR part 503. EPA
has set ceiling limitations for nine metals in sludge that is land
applied, three metals in sludge that is placed on a surface disposal
unit, and seven metals and 57 organic pollutants in sludge that is
incinerated in a sewage sludge incinerator. 40 CFR 403.7(a)(3)(iv)(A).
(2) Additional removal credits may be available for sewage sludge
that is land applied, placed in a surface disposal unit, or incinerated
in a sewage sludge incinerator, so long as the concentration of these
pollutants in sludge do not exceed concentration levels established in
part 403, Appendix G, Table II. For sewage sludge that is land applied,
removal credits may be available for an additional two metals and 14
organic pollutants. For sewage sludge that is placed on a surface
disposal unit, removal credits may be available for an additional seven
metals and 13 organic pollutants. For sewage sludge that is incinerated
in a sewage sludge incinerator, removal credits may be available for
three other metals 40 CFR 403.7(a)(3)(iv)(B).
(3) When a POTW disposes of its sewage sludge in a municipal solid
waste landfill that meets the criteria of 40 CFR part 258, removal
credits may be available for any pollutant in the POTW's sewage sludge.
40 CFR 403.7(a)(3)(iv)(C).
[[Page 34526]]
XVII. Related Acts of Congress, Executive Orders, and Agency
Initiatives
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
Under Section 3(f)(1) of Executive Order (EO) 12866 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to have an annual effect on
the economy of $100 million or more. Accordingly, EPA submitted this
action to the Office of Management and Budget (OMB) for review under
Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any
changes made in response to OMB recommendations have been documented in
the docket for this action.
In addition, EPA prepared an analysis of the potential costs and
benefits associated with this action. This analysis is contained in
Chapter 12 of the BCA report. A copy of the analysis is available in
the docket for this action and the analysis is briefly summarized here.
Table XVII-1 (drawn from Table 12-1 of the BCA report) provides the
results of the benefit-cost analysis with both costs and benefits
annualized over 24 years and discounted using a 3 percent discount
rate. The table lists the eight options in order of increasing total
social costs.
Table XVII-1--Total Monetized Annualized Benefits and Costs of the BAT
and PSES Regulatory Options
[Millions 2010 $, 3 percent discount rate] \a\
------------------------------------------------------------------------
Total
Total monetized
Regulatory option social benefits
costs \b\ \c\ \d\ \e\
------------------------------------------------------------------------
Option 3a..................................... $185.2 (\e\)
Option 1...................................... 268.3 $82.0
Option 3b..................................... 281.4 (\e\)
Option 2...................................... 386.8 111.7
Option 3...................................... 572.0 311.7
Option 4a..................................... 954.1 (\e\)
Option 4...................................... 1,381.2 605.5
Option 5...................................... 2,328.8 434.1
------------------------------------------------------------------------
\a\ All costs and benefits were annualized over 24 years and using a 3
percent discount rate.
\b\ Total social costs include compliance costs to facilities.
\c\ Mean benefit estimates. Values include partial human health benefits
only for reaches that receive direct discharges from steam electric
plants. Values for Options 1, 2, and 5 do not include air-related
benefits.
\d\ EPA estimated certain benefits for Options 3 and 4 only. Total
benefits for Options 1, 2, and 5 are therefore understated. See
Section XIV and Table XIV-8.
\e\ EPA did not estimate benefits for Options 3a, 3b and 4a. The
benefits of Option 4a are expected to be between those of Options 3
and 4.
EPA also analyzed the employment effects of the proposed ELGs. The
results of that analysis are summarized in Section XI.E.
B. Paperwork Reduction Act
This action does not impose any new information collection burden.
However, the Office of Management and Budget (OMB) has previously
approved the information collection requirements contained in the
existing regulations 40 CFR part 423 under the provisions of the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB
control number 2040-0281. The OMB control numbers for EPA's regulations
in 40 CFR are listed in 40 CFR part 9.
EPA estimated small changes in monitoring costs due to additional
metals for which EPA is proposing limits and standards; the Agency
accounted for these costs as part of its analysis of the economic
impacts of the proposed ELGs. However, plants will also realize certain
savings by no longer monitoring effluent that would cease to exist
under the proposed ELGs. The net changes in monitoring and reporting
are expected to be minimal, and EPA consequently did not revise its
information collection burden estimate.
EPA does not believe that the proposed rule would lead to
additional costs to permitting authorities. The proposed rule would not
change permit application requirements or the associated review, it
would not increase the number of permits issued to steam electric
plants, and nor it increase the efforts involved in developing or
reviewing such permits. In the absence of nationally applicable BAT
requirements, as appropriate, permitting authorities are directed to
establish technology-based effluent limitations using their use best
professional judgment (BPJ) to establish site-specific requirements.
EPA has data that demonstrates that permitting authorities that
establish technology-based effluent limitations on a BPJ basis based on
site-specific conditions can spend significant time effort and
resources doing so. Establishing nationally applicable BAT requirements
that eliminate the need to develop BPJ-based limitations would make
permitting easier and less costly in this respect. As explained in
Section XVI, under this rule, permitting authorities would be required
to determine, for one permit cycle, on a facility-specific basis, what
date is ``as soon as possible.'' This one-time burden, however, would
be no more excessive than the existing burden to develop technology-
based effluent limitations on a BPJ basis; in fact, it would likely be
less burdensome. Nevertheless, EPA conservatively estimated no net
change (i.e., increase or decrease) in the cost burden to federal or
state governments associated with this proposal.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice-and-comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
1. Definition of Small Entities and Estimation of the Number of Small
Entities Subject to These Proposed ELGs
For purposes of assessing the impacts of this proposed rule on
small entities, small entity is defined as either a: (1) A small
business as defined by the Small Business Administration's (SBA)
regulations at 13 CFR 121.201; (2) a small governmental jurisdiction
that is a government of a city, county, town, school district or
special district with a population of less than 50,000; or (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field. In
reaching entity size determinations, EPA assumed that all federal or
state entities owning steam electric plants affected by this rulemaking
are not small entities.
The SBA criteria for identifying small, non-government entities in
the electric power industry are as follows:
For non-government entities with electric power generation
as a primary business, small entities are those with total annual
electric output less than 4 million MWh;
For non-federal or state jurisdictions, small entities are
those with a population of less than 50,000.
For entities with a primary business other than electric
power generation, the relevant size criteria are based on revenue or
number of employees by NAICS sector (see Table XVII-2).
[[Page 34527]]
Table XVII-2--NAICS Codes and SBA Entity Size Standards for Steam
Electric Generators with a Primary Business Other Than Electric Power
Generation a
------------------------------------------------------------------------
SBA size standard
NAICS Code NAICS description \b\
------------------------------------------------------------------------
211111............ Crude Petroleum and Natural 500 Employees.
Gas Extraction.
212111............ Bituminous Coal and Lignite 500 Employees.
Surface Mining.
213112............ Support Activities for Oil and $7 million in
Gas Operations. revenue.
221210............ Natural Gas Distribution...... 500 Employees.
221310............ Water Supply and Irrigation $7 million in
Systems. revenue.
221330............ Steam and $12.5 million in
Air[dash]Conditioning Supply. revenue.
237130............ Power and Communication Line $33.5 million in
and Related Structures revenue.
Construction.
324110............ Petroleum Refineries.......... 1,500 Employees.
332410............ Power Boiler and Heat 500 Employees.
Exchanger Manufacturing.
333611............ Turbine and Turbine Generator 1,000 Employees.
Set Unit Manufacturing.
423510............ Metal Service Centers and 100 Employees.
Other Metal Merchant
Wholesalers.
486110............ Pipeline Transportation of 1,500 Employees.
Crude Oil.
522110............ Commercial Banking............ $175 million in
assets.
523110............ Investment Banking and $7 million in
Securities Dealing. revenue.
523910............ Miscellaneous Intermediation.. $7 million in
revenue.
523920............ Portfolio Management.......... $7 million in
revenue.
524113............ Direct Life Insurance Carriers $7 million in
revenue.
524126............ Direct Property and Casualty 1,500 employees.
Insurance Carriers.
525910............ Open[dash]End Investment Funds $7 million in
revenue.
541614............ Process, Physical Distribution $14 million in
and Logistics Consulting revenue.
Services.
541690............ Other Scientific and Technical $14 million in
Consulting Services. revenue.
551111............ Offices of Bank Holding $7 million in
Companies. revenue.
551112............ Offices of Other Holding $7 million in
Companies. revenue.
562219............ Other Nonhazardous Waste $12.5 million in
Treatment and Disposal. revenue.\c\
------------------------------------------------------------------------
\a\ Certain plants affected by this rulemaking are owned by non-
government entities whose primary business is not electric power
generation.
\b\ Based on size standards effective at the time EPA conducted this
analysis (SBA size standards, effective October 1, 2012).
\c\ EPA is aware that SBA revised the size standard applicable to this
sector, effective January 7, 2013 (from $12.5 million in revenue to
$35.5 million in revenue); EPA used the size standards effective at
the time the analyses were completed and will update the size
standards as part of revisions to support final rulemaking.
EPA identified the domestic parent entity of each steam electric
plant and obtained the entity's revenue from the Steam Electric
industry survey or from publicly available data sources. In this
analysis, the domestic parent entity associated with any given plant is
defined as that entity that has the largest ownership share in the
plant. To determine whether these entities are small entities based on
the size criteria outlined above, EPA compared the relevant measure for
the identified parent entities to the appropriate SBA size criterion.
EPA used alternative sample-weighting approaches, which provide a
range of estimates of the numbers of small entities and affected plants
owned by these small entities (see Chapter 8 in the RIA for details of
methodology used to develop weighted estimates). The results of this
analysis using both weighting approaches are summarized below.
EPA estimates that 243 to 507 entities own steam electric plants
subject to this proposal. Applying the small entity identification
criteria, EPA estimates that 97 to 170 of these entities are small (see
Table XVII-3). Municipalities make up the largest number of small
entities owning steam electric plants under the lower bound estimate
(37 out of 97) and are also a significant fraction of small entities
under the upper bound estimate (46 out of 170). Small entities owning
steam electric plants as a percentage of total entities range, by
ownership category, from 14 to 17 percent for other political
subdivision, to 47 to 51 percent for nonutility and 45 to 57 percent
for municipality.
EPA determined that 14 small entities own steam electric plants
expected to incur compliance costs under at least one of the eight
regulatory options, for either of the two bounding cases.
Table XVII-3--Number of Entities Owning Steam Electric Plants by Sector and Size
[Assuming two different ownership cases] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Lower bound estimate of number of entities Upper bound estimate of number of entities
owning steam electric plants \b\ owning steam electric plants \b\
Ownership type -----------------------------------------------------------------------------------------------
Total Small \c\ % Small Total Small \c\ % Small
--------------------------------------------------------------------------------------------------------------------------------------------------------
Investor-Owned Utilities................................ 97 27 27.8 244 64 26.3
Nonutilities............................................ 35 18 51.4 73 34 46.8
Rural Electric Cooperatives............................. 30 13 43.3 52 21 40.7
Municipality............................................ 65 37 56.9 101 46 45.3
Other Political Subdivision............................. 12 2 16.7 30 4 14.2
Federal \a\............................................. 2 0 0.0 4 0 0.0
State \a\............................................... 2 0 0.0 2 0 0.0%
Tribal.................................................. 0 0 N/A 0 0 N/A
All Entity Types........................................ 243 97 39.9 507 170 33.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ In 19 instances, a plant is owned by a joint venture of two entities; in one instance, the plant is owned by a joint venture of three entities.
[[Page 34528]]
\b\ Of these, 92 entities, 14 of which are small, own steam electric plants that are expected to incur compliance costs under at least one regulatory
option under both Case 1 and Case 2.
\c\ EPA was unable to determine size for 10 parent entities; for this analysis, these entities are assumed to be small.
In total, small entities own a total of 189 steam electric plants,
or 18 percent of the total universe of 1,079 steam electric plants. Of
these, EPA determined that 14 plants may incur compliance costs under
at least one of the eight regulatory options.
EPA notes that its proposal (discussed in Section VIII) to set the
BAT equal to BPT for existing generating units with a total nameplate
generating capacity of 50 MW or less for all of the eight proposed
regulatory options will reduce the potential impacts of the proposed
rule on small entities and municipalities. The rulemaking record
indicates that establishing a size threshold for the BAT would
preferentially minimize some of the economic impacts expected on
municipalities and small entities. This is the result, in particular,
of the fact that 37 percent of small entities own a steam electric
generating unit with a capacity of 50 MW or smaller. This stands in
contrast to the 22 percent of all firms (both large and small entities)
that own such a unit and the 18 percent of large entities that own one.
Moreover, more than half (54 percent) of generating units owned by
small entities are 50 MW or smaller. In contrast, only seven percent of
generating units owned by large entities are 50 MW or smaller.
Municipalities also tend to own smaller generating units, with 30
percent of municipalities and 42 percent of municipal-owned units being
affected by the 50 MW size threshold.
EPA requests comment on the proposed 50 MW threshold applicable to
discharges of the wastestreams described under each of the preferred
options, and as well as other possible thresholds for small units.
2. Statement of Basis
As described above, EPA began its assessment of the impact of
regulatory options on small entities by first estimating the number of
small entities owning Steam Electric plants that would be subject to
these proposed ELGs. EPA then assessed whether these small entities
would be expected to incur costs that constitute a significant impact;
and whether the number of those small entities estimated to incur a
significant impact represent a substantial number of small entities.
To assess whether small entities' compliance costs might constitute
a significant impact, EPA summed annualized compliance costs for the
steam electric plants determined to be owned by a given small entity
and calculated these costs as a percentage of entity revenue (cost-to-
revenue test). EPA compared the resulting percentages to impact
criteria of 1 percent and 3 percent of revenue. Small entities
estimated to incur compliance costs exceeding one or more of the 1
percent and 3 percent impact thresholds were identified as potentially
incurring a significant impact.
EPA used alternative sample-weighting approaches, which provide a
range of estimates of the numbers of small entities and steam electric
plants owned by these small entities. The results of this analysis
using both weighting approaches are summarized below. Table XVII-4
presents the estimated numbers of small entities incurring costs
exceeding 1 percent and 3 percent of revenue. For more information on
this analysis in general and the weighting approaches in particular,
see Chapter 7 in the RIA report.
Table XVII-4--Estimated Cost-to-Revenue Impact on Small Entities Owning Steam Electric Plants Subject to This
Proposed Rule
[Excluding those below the size threshold]
----------------------------------------------------------------------------------------------------------------
Cost >=1% of revenue Cost >=3% of revenue
-----------------------------------------------------------------------
Regulatory option % of small % of small
Number of small affected Number of small affected
entities entities \b\ entities \a\ entities \b\
----------------------------------------------------------------------------------------------------------------
Lower bound estimate of number of entities owning steam electric plants
----------------------------------------------------------------------------------------------------------------
Option 3a............................... 0 0.0 0 0.0
Option 3b............................... 0 0.0 0 0.0
Option 1................................ 3 3.1 3 3.1
Option 2................................ 5 5.2 3 3.1
Option 3................................ 5 5.2 3 3.1
Option 4a............................... 6 6.2 4 4.1
Option 4................................ 12 12.4 4 4.1
Option 5................................ 12 12.4 7 7.2
----------------------------------------------------------------------------------------------------------------
Upper bound estimate of number of entities owning steam electric plants
----------------------------------------------------------------------------------------------------------------
Option 3a............................... 0 0.0 0 0.0
Option 3b............................... 0 0.0 0 0.0
Option 1................................ 3 1.8 3 1.8
Option 2................................ 5 2.9 3 1.8
Option 3................................ 5 2.9 3 1.8
Option 4a............................... 6 3.5 4 2.4
Option 4................................ 12 7.1 4 2.4
Option 5................................ 12 7.1 7 4.1
----------------------------------------------------------------------------------------------------------------
\a\ The number of entities with cost-to-revenue ratios exceeding 3 percent is a subset of the number of entities
with such ratios exceeding 1 percent.
\b\ Percentage values were calculated relative to the total of 97 (Case 1) and 170 (Case 2) small entities
owning steam electric plants.
[[Page 34529]]
As reported in Table XVII-4, EPA estimates that between 0 and 12
small entities owning steam electric plants will incur costs exceeding
1 percent of revenue, and that between 0 and 7 small entities owning
steam electric plants will incur costs exceeding 3 percent of revenue,
depending on the regulatory option. This is out of an estimated total
of 97 to 170 small entities owning steam electric plants. The impact
findings in terms of numbers of entities affected at different levels,
and the percentage of small entities by ownership category vary by
regulatory option. Overall across entity types, no small entity is
estimated to have costs exceeding 1 percent of revenue under Options 3a
and 3b. Under Option 3, 5 small entities are estimated to have costs
exceeding 1 percent of revenue, and 3 small entities have costs
exceeding 3 percent of revenue. Under Option 4a, 6 small entities are
estimated to have costs 1 percent of revenue or higher under Option 3,
and 4 small entities have costs 3 percent of revenue or higher. Table
XVII-5 presents the distribution of these entities by ownership type
for Options 3 and 4a (Options 3a and 3b are not included in the table
since no small entity has costs 1 percent of revenue or higher under
these two options). As shown in the table, small entities with costs 1
percent of revenue or greater under Option 3 include 2 cooperatives and
3 municipalities. Under Option 4a, 2 cooperatives and 4 municipalities
have costs 1 percent of revenue or greater. The cost-to-revenue test is
one of several metrics EPA used to determine the impacts of the
proposed ELGs. As discussed in Section XI.D, EPA also looked at impacts
in the context of the electricity market-level effects to assess
economic achievability.
Table XVII-5--Estimated Cost-to-Revenue Impact on Small Entities Owning Steam Electric Plants Under the Preferred BAT and PSES Options (Options 3 and
4a), by Ownership Type (Excluding Those Below the Size Threshold) a
--------------------------------------------------------------------------------------------------------------------------------------------------------
Lower bound estimate of number of entities owning Upper bound estimate of number of entities owning
steam electric plants steam electric plants
----------------------------------------------------------------------------------------------------------------
Cost >=1% of revenue Cost >=3% of revenue Cost >=1% of revenue Cost >=3% of revenue
Regulatory option ----------------------------------------------------------------------------------------------------------------
Number of % of small Number of % of small Number of % of small Number of % of small
small affected small affected small affected small affected
entities entities \c\ entities \b\ entities \c\ entities entities \c\ entities \b\ entities \c\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3:
Cooperative........................ 2 15.4 2 15.4 2 9.4 2 9.4
Investor-Owned..................... 0 0.0 0 0.00 0 0.0 0 0.0
Municipality....................... 3 8.1 1 2.7 3 6.5 1 2.2
Nonutility......................... 0 0.0 0 0.0 0 0.0 0 0.0
Other Political Subdivision........ 0 0.0 0 0.0 0 0.0 0 0.0
----------------------------------------------------------------------------------------------------------------
Total.......................... 5 5.2 3 3.1 5 2.9 3 1.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 4a:
Cooperative........................ 2 15.4 2 15.4 2 9.4 2 9.4
Investor-Owned..................... 0 0.0 0 0.0 0 0.0 0 0.0
Municipality....................... 4 10.8 2 5.4 4 8.7 2 4.4
Nonutility......................... 0 0.0 0 0.0 0 0.0 0 0.0
Other Political Subdivision........ 0 0.0 0 0.0 0 0.0 0 0.0
----------------------------------------------------------------------------------------------------------------
Total.......................... 6 6.2 4 4.1 6 3.5 4 2.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Options 3a and 3b are not included in the table since no small entity has costs 1 percent of revenue or higher under these two preferred options.
\b\ The number of entities with cost-to-revenue ratios exceeding 3 percent is a subset of the number of entities with such ratios exceeding 1 percent.
\c\ Percentage values were calculated relative to the total of 97 (Case 1) and 170 (Case 2) small entities owning steam electric plants. EPA expects
that Case 2 is a more likely ownership scenario for small entities (e.g., small municipalities) as small entities may be less likely to own multiple
non-surveyed steam electric plants. See RIA Chapter 8 for details.
Based on this analysis, EPA determines that the small entity impact
levels for the preferred BAT and PSES options (Options 3a, 3b, 3 and
4a) support a finding of no significant impact on a substantial number
of small entities (No SISNOSE). Where not zero altogether, the numbers
of small entities incurring costs exceeding either the 1 or 3 percent
of revenue impact threshold are small in the absolute and represent
small percentages of the total estimated number of small entities (see
Table XVII-5). For more details on this
[[Page 34530]]
analysis, see Chapter 8 of the RIA report.
3. Certification Statement
After considering the economic impacts of these proposed ELGs on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. EPA bases
its finding on the low number of small entities estimated to incur
costs exceeding one and/or three percent of revenue, and the small
percentage that these entities represent within the total of small
entities owning steam electric plants. EPA continues to be interested
in the potential impacts of the proposed rule on small entities and
welcomes comments on issues related to potential impacts.
D. Unfunded Mandates Reform Act (UMRA)
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2
U.S.C. 1531-1538, requires federal agencies, unless otherwise
prohibited by law, to assess the effects of their regulatory actions on
State, local, and tribal governments and the private sector. This rule
contains a federal mandate that may result in expenditures of $100
million or more for State, local, and tribal governments, in the
aggregate, or the private sector in any one year. Accordingly, EPA has
prepared under Section 202 of the UMRA a written statement, which is
summarized below (see Chapter 9 in the RIA report for more details).
Consistent with the intergovernmental consultation provisions of
Section 204 of the UMRA EPA has initiated consultations with
governmental entities affected by this rule. As described in Sections
XVII.E, EPA held consultation meetings with elected officials or their
designated employees in October 2011 to ensure their meaningful and
timely input into the proposed ELGs development. EPA also conducted
outreach with several intergovernmental associations representing
elected officials. As described in Section XVII.F, EPA also initiated
consultation and coordination with federally-recognized tribal
governments in August 2011 and continued this government-to-government
dialogue in March 2012.
Consistent with Section 205, EPA has identified and considered a
reasonable number of regulatory alternatives. EPA considered and
analyzed several alternative regulatory options to determine BAT/BADCT.
These regulatory options are discussed in Section VIII of this
preamble. These options included a range of technology-based
approaches. As discussed in detail in Section VIII, EPA is proposing
Options 3a, 3b, 3 and 4a as the preferred BAT and PSES options because
they are technologically available, economically achievable, and have
acceptable non-water quality environmental impacts. EPA is proposing
Option 4 as the preferred NSPS and PSNS option because it is
technologically available and demonstrated, poses no barrier to entry,
and has acceptable non-water quality environmental impacts.
This rule is not subject to the requirements of Section 203 of UMRA
because it contains no regulatory requirements that might significantly
or uniquely affect small governments. For its assessment of the impact
of compliance requirements on small governments (i.e., governments with
a population of less than 50,000), EPA compared total costs and costs
per plant estimated to be incurred by small governments with the costs
estimated to be incurred by large governments. EPA also compared costs
for small government-owned plants with those of non-government-owned
facilities. The Agency evaluated both the average and maximum
annualized cost per plant. Chapter 9 of the RIA report provides details
of these analyses. In all of these comparisons, both for the cost
totals and, in particular, for the average and maximum cost per plant,
the costs for small government-owned facilities were less than those
for large government-owned facilities or for small non-government-owned
facilities. On this basis, EPA concludes that the compliance cost
requirements of the proposed Steam Electric ELGs would not
significantly or uniquely affect small governments.
E. Executive Order 13132: Federalism
Under Executive Order 13132, EPA may not issue an action that has
federalism implications, that imposes substantial direct compliance
costs, and that is not required by statute, unless the Federal
government provides the funds necessary to pay the direct compliance
costs incurred by State and local governments, or EPA consults with
state and local officials early in the process of developing the
proposed action.
EPA has concluded that this action may have federalism
implications, because it may impose substantial direct compliance costs
on state or local governments, and the federal government will not
provide the funds necessary to pay those costs.
As discussed in Section XI, EPA anticipates that this proposed
action will not impose incremental administrative burden on states from
issuing, reviewing, and overseeing compliance with discharge
requirements. However, EPA has identified 168 steam electric plants
owned by state or local government entities, out of which less than 10
percent may incur costs under one of the preferred regulatory Options.
Specifically, EPA projects that five government-owned plants incur
compliance costs under BAT/PSES regulatory Option 3a, six plants incur
compliance costs under Option 3b, 14 plants incur compliance costs
under Option 3, and 15 plants incur compliance costs under Option 4a.
EPA estimates that the maximum compliance cost in any one year to
governments (excluding federal government) for the eight regulatory
options ranges from $13.8 million under Option 3a to $406.2 million
under Option 5. Options 3b, 3 and 4a have maximum compliance costs in
any one year to governments of $31.9 million, $109.5 million and $141.8
million, respectively (see Chapter 9 of the RIA report for details).
From these cost values, EPA determined that the proposed ELGs contain a
federal mandate that may result in expenditures of $100 million or more
for state, local, and tribal governments, in the aggregate, in any one
year. Based on this information, EPA finds that the action may impose
substantial direct compliance costs on state or local governments.
Accordingly, EPA provides the following federalism summary impact
statement as required by Section 6(b) of Executive Order 13132.
EPA consulted with elected officials or their representative
national organizations early in the process of developing the proposed
action to permit them to have meaningful and timely input into its
development.
EPA invited government officials to a consultation meeting held on
October 11, 2011. EPA conducted outreach with several intergovernmental
associations representing elected officials and encouraged their
members to participate in the meeting, including the National Governors
Association, the National Conference of State Legislatures, the Council
of State Governments, the National Association of Counties, the
National League of Cities, the U.S. Conference of Mayors, the County
Executives of America and the National Associations of Towns and
Townships.
Over 50 participants attended the consultation by phone and another
20 attended the meeting in person. EPA representatives were also
present. Participants raised concerns during the meeting and in written
comments
[[Page 34531]]
regarding the technology options, pollutant removal effectiveness,
costs of specific technologies and overall costs, impacts on small
generating units and on small governments, and generally requested more
detailed information. They also expressed their concern with regulating
the industry at this time given the difficult economic conditions.
As explained in Section VIII, under all eight proposed regulatory
options, EPA is proposing differentiated requirements for oil-fired
generating units and units 50 MW or less. EPA believes these
differentiated requirements will alleviate some of the concerns raised
above. Further, as explained in Section XI, EPA's analysis demonstrates
that the proposed requirements are economically achievable for the
steam electric industry as a whole and for plants owned by state or
local government entities. EPA is including in the docket for this
action a memorandum that provides a response to the comments it
received through this consultation. In the spirit of Executive Order
13132, and consistent with EPA policy to promote communications between
EPA and State and local governments, EPA specifically solicits comment
on the proposed ELGs from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It would not
have substantial direct effects on tribal governments, on the
relationship between the federal government and the Indian tribes, or
the distribution of power and responsibilities between the Federal
government and Indian tribes as specified in Executive Order 13175.
EPA's analyses show that no facility subject to these proposed ELGs is
owned by tribal governments. Thus, Executive Order 13175 does not apply
to this action.
Although Executive Order 13175 does not apply to this action, EPA
consulted with tribal officials in developing this action. EPA
initiated consultation and coordination with federally recognized
tribal governments in August 2011, sharing information about the steam
electric effluent guidelines rulemaking with the National Tribal Caucus
and the National Tribal Water Council. EPA continued this government-
to-government dialogue and, in March 2012, invited tribal
representatives to participate in further discussions about the
rulemaking process and objectives, with a focus on identifying specific
ways that the rulemaking may affect tribes. EPA mailed an invitation
letter directly to those tribes that were preliminarily identified as
potentially affected by the rulemaking, as well extended the invitation
via email to all federally-recognized tribal governments encouraging
their participation in the consultation process. The consultation
process ended on April 17, 2012 and no comments were received from any
tribal representative. For further information regarding the
consultation process and supplemental materials provided to tribal
representatives please go to the steam electric power generating
effluent guidelines Web site at this link: http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm#point8. EPA specifically
solicits additional comment on this proposed action from tribal
officials.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is not subject to Executive Order 13045 (62 FR 19885,
April 23, 1997) because the Agency does not believe the environmental
health risks or safety risks addressed by this action present a
disproportionate risk to children. This proposed action's health and
risk assessments are summarized in Section XIV.D.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355 (May 22, 2001)) because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy.
The Agency analyzed the potential energy effects of these proposed
ELGs. The potentially significant effects of this rule on energy
supply, distribution or use concern the electric power sector. EPA's
analysis found that the proposed ELGs would not cause effects in the
electric power sector that would constitute a significant adverse
effect under Executive Order 13211. Namely, the Agency's analysis found
that this rule would not reduce electricity production in excess of 1
billion kilowatt hours per year or in excess of 500 megawatts of
installed capacity, and therefore would not constitute a significant
regulatory action under Executive Order 13211.
For more detail on the potential energy effects of this proposal,
see Chapter 10 in the RIA report.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272
note), directs EPA to use voluntary consensus standards in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, and business practices) that are developed or
adopted by voluntary consensus standards bodies. NTTAA directs EPA to
provide Congress, through OMB, explanations when the Agency decides not
to use available and applicable voluntary consensus standards.
This rulemaking does not involve technical standards, for example,
in the measurement of pollutant loads. Nothing in this proposed rule
would prevent the use of voluntary consensus standards for such
measurement where available, and EPA encourages permitting authorities
and regulated entities to do so. Therefore, EPA is not considering the
use of any voluntary consensus standards.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it increases the
level of environmental protection for all affected populations without
having any disproportionately high and adverse human health or
environmental effects on any population, including any minority or low-
income population.
To meet the objectives of Executive Order 12898, EPA examined
whether these proposed ELGs will have potential environmental justice
concerns in the areas affected by steam electric plant
[[Page 34532]]
discharges. The Agency analyzed the demographic characteristics of the
populations currently exposed to steam electric plant discharges
through receiving reaches (i.e., populations located within 100 miles
of the affected reaches, also referred to as the ``benefit regions'' in
the rest of this discussion) to determine whether minority and or low-
income populations are subject to disproportionally high environmental
impacts. Chapter 10 of the RIA provides a detailed discussion of the
environmental justice analysis.
EPA compared demographic data from the 2010 Census for benefit
regions with corresponding characteristics at the state and national
levels. This analysis focuses on the spatial distribution of minority
and low-income groups to determine whether these groups are more or
less represented in the populations expected to benefit from the
proposed ELGs. The demographic characteristics that EPA analyzed
include: percent African Americans, percent Native American, Eskimo, or
Aleut, percent Asian or Pacific Islander, percent of the population
below the poverty level, and median income. This analysis shows that
approximately 14 percent of households in affected populations are
below the poverty threshold, and 25 percent of them are minority,
compared with national averages of 14 percent and 36 percent,
respectively. Additionally, the median household income in affected
populations is $48,579, while it is $51,914 nationally.
Of the 344 benefit regions defined in the analysis (within 100
miles of an affected plant), 28 regions (8 percent) may have
Environmental Justice concerns under all three metrics, 79 regions (23
percent) under two metrics, and 194 regions (56 percent) under one
metric. Forty-three regions (13 percent) would not be considered has
having Environmental Justice concerns under any of the metrics.
This analysis indicates that minority and low-income communities
are expected to benefit as much as anyone from the proposed ELGs.
Appendix A: Definitions, Acronyms, and Abbreviations Used in This
Notice
The following acronyms and abbreviations are used in this
document.
Administrator--The Administrator of the U.S. Environmental
Protection Agency.
Agency--U.S. Environmental Protection Agency.
BAT--Best available technology economically achievable, as
defined by Sections 301(b)(2)(A) and 304(b)(2)(B) of the CWA.
BCT--The best control technology for conventional pollutants,
applicable to discharges of conventional pollutants from existing
industrial point sources, as defined by Sections 301(b)(2)(E) and
304(b)(4) of the CWA.
BMP--Best management practice.
Bottom ash--The ash, including boiler slag, that drops out of
the furnace gas stream in the furnace and which settles in the
furnace or are dislodged from furnace walls. Economizer ash is
included when it is collected with bottom ash.
BPT--The best practicable control technology currently
available, applicable to effluent limitations, for industrial
discharges to surface waters, as defined by Sections 301(b)(1) and
304(b)(1) of the CWA.
CBI--Confidential Business Information.
CCR--Coal Combustion Residuals.
Clean Water Act (CWA)--The Federal Water Pollution Control Act
Amendments of 1972 (33 U.S.C. Section 1251 et seq.), as amended
e.g., by the Clean Water Act of 1977 (Pub. L. 95-217), and the Water
Quality Act of 1987 (Pub. L. 100-4).
Combustion Residual Leachate--Leachate from landfills or surface
impoundments containing combustion residuals. Leachate includes
liquid, including any suspended or dissolved constituents in the
liquid that has percolated through or drained from waste or other
materials emplaced in a landfill, or that pass through the
containment structure (e.g., bottom, dikes, berms) of a surface
impoundment. Leachate also includes the terms seepage, leak, and
leakage, which are generally used in reference to leachate from an
impoundment. Includes landfills and surface impoundments located on
non-adjoining property when under the operational control of the
permitted facility.
Direct Discharger--A facility that discharges or may discharge
treated or untreated wastewaters into waters of the United States.
DOE--Department of Energy.
Dry bottom ash handling system--A system that does not use water
to convey bottom ash away from the boiler. It includes systems that
collect and convey the ash without any use of water, as well as
systems in which bottom ash is mechanically or pneumatically
conveyed away from the boiler.
Dry fly ash handling system--A system that does not use water as
the transport medium to convey fly ash away from particulate
collection equipment.
EIA--Energy Information Administration.
EO--Executive Order.
EPA--U.S. Environmental Protection Agency.
Facility -- All property owned, operated, leased, or under the
control of the same person or entity.
Flue Gas Desulfurization (FGD) Wastewater--Any process
wastewater generated specifically from the wet flue gas
desulfurization scrubber system, including any solids separation or
solids dewatering processes.
Flue Gas Mercury Control (FGMC) System--An air pollution control
system installed or operated for the purpose of removing mercury
from flue gas.
Flue Gas Mercury Control Wastewater--Any process wastewater
generated from an air pollution control system installed or operated
for the purpose of removing mercury from flue gas. This includes fly
ash collection systems when the particulate control system follows
the injection of sorbents or implementation of other controls to
remove mercury from flue gas. Flue gas desulfurization systems are
not included in this definition.
Fly Ash--The ash that is carried out of the furnace by the gas
stream and collected by mechanical precipitators, electrostatic
precipitators, and/or fabric filters. Economizer ash is included
when it is collected with fly ash. Ash collected in wet scrubber air
pollution control systems whose primary purpose is particulate
removal is not included.
Gasification Wastewater--Wastewater from all sources at an
integrated gasification combined cycle operation except those for
which specific limitations are otherwise established. Gasification
wastewater includes, but is not limited to the following: slag
handling wastewater; fly ash and water stream; sour/grey water
(which consists of condensate generated for gas cooling, as well as
other wastestreams); CO2/steam stripper wastewater; air
separation unit blowdown; and sulfur recover unit blowdown.
IPM--Integrated Planning Model.
Landfill--A disposal facility or part of a facility where solid
waste, sludges, or other process residuals are placed in or on any
natural or manmade formation in the earth for disposal and which is
not a storage pile, a land treatment facility, a surface
impoundment, an underground injection well, a salt dome or salt bed
formation, an underground mine, a cave, or a corrective action
management unit.
Low Volume Waste Sources--Wastewater from all sources including,
but not limited to: ion exchange water treatment systems, water
treatment evaporator blowdown, laboratory and sampling streams,
boiler blowdown, floor drains, cooling tower basin cleaning wastes,
and recirculating house service water systems. Sanitary and air
conditioning wastes and carbon capture wastewater are not included.
NAICS--North American Industry Classification System.
NSPS, or New Source Performance Standards, applicable to
industrial facilities whose construction is begun after the
effective date of the final regulations. See 40 CFR 122.2.
ORCR--Office of Resource Conservation and Recovery.
PSES--Pretreatment Standards for Existing Sources.
PSNS--Pretreatment Standards for New Sources.
Publicly Owned Treatment Works (POTW)--Any device or system,
owned by a state or municipality, used in the treatment (including
recycling and reclamation) of municipal sewage or industrial wastes
of a liquid nature that is owned by a state or municipality. This
includes sewers, pipes, or other conveyances only if they convey
wastewater to a POTW providing treatment. See 40 CFR 122.2.
RCRA--The Resource Conservation and Recovery Act of 1976, 42
U.S.C. 6901 et seq.
[[Page 34533]]
RFA--Regulatory Flexibility Act.
SBA--Small Business Administration.
Surface Impoundments--A facility or part of a facility which is
a natural topographic depression, man-made excavation, or diked or
dammed area formed primarily of earthen materials (although it may
be lined with man-made materials), which is designed to hold an
accumulation of liquid process wastes or process wastes containing
free liquids, and which is not an injection well. Examples of
surface impoundments are holding, storage, settling, and aeration
pits, ponds, and lagoons.
UMRA--Unfunded Mandates Reform Act.
Wet bottom ash handling system--A system in which bottom ash is
conveyed away from the boiler using water as a transport medium. Wet
bottom ash systems typically send the ash slurry to dewatering bins
or a surface impoundment.
Wet FGD system--Wet FGD systems capture sulfur dioxide from the
flue gas using a sorbent that has mixed with water to form a wet
slurry, and that generates a water stream that exits the FGD
scrubber absorber.
Wet fly ash handling system--A system that conveys fly ash away
from particulate removal equipment using water as a transport
medium. Wet fly ash systems typically dispose of the ash slurry in a
surface impoundment.
List of Subjects 40 CFR Part 423
Environmental protection, Electric power generation, Power plants,
Waste treatment and disposal, Water pollution control.
Dated: April 19, 2013.
Bob Perciasepe,
Acting Administrator.
Therefore, 40 CFR chapter I is proposed to be amended as follows:
PART 423--STEAM ELECTRIC POWER GENERATING POINT SOURCE CATEGORY
0
1. The authority citation for part 423 is revised to read as follows:
Authority: Secs. 101; 301; 304(b), (c), (e), and (g); 306; 307;
308 and 501, Clean Water Act (Federal Water Pollution Control Act
Amendments of 1972, as amended; 33 U.S.C. 1251; 1311; 1314(b), (c),
(e), and (g); 1316; 1317; 1318 and 1361).
0
2. Section 423.10 is revised as follows:
Sec. 423.10 Applicability.
The provisions of this part apply to discharges resulting from the
operation of a generating unit by an establishment whose generation of
electricity is the predominant source of revenue or principal reason
for operation, and which results primarily from a process utilizing
fossil-type fuel (coal, oil, or gas), fuel derived from fossil fuel
(e.g., petroleum coke, synthesis gas), or nuclear fuel in conjunction
with a thermal cycle employing the steam water system as the
thermodynamic medium. This part applies to discharges associated with
both the combustion turbine and steam turbine portions of a combined
cycle generating unit. Facilities defined as new sources under the 1982
new source performance standards specified in Sec. Sec. 423.15(a) and
423.17(a) of this part continue to be subject to those standards. Units
that qualify as 1982 new sources are also subject to revised BAT
effluent limitations specified in Sec. 423.13 of this part (for direct
dischargers) or the revised pretreatment standards specified in Sec.
423.16 of this part (for indirect dischargers). These revised
limitations and standards constitute amendments to the new source
performance standards applicable to 1982 new sources.
0
3. Section 423.11 is amended by:
0
a. Revising paragraphs (b) and (e); and
0
b. Adding paragraphs (n) through (u).
The revised and added paragraphs read as follows:
Sec. 423.11 Specialized definitions.
* * * * *
(b) The term low volume waste sources means, taken collectively as
if from one source, wastewater from all sources except those for which
specific limitations are otherwise established in this part. Low volume
waste sources include, but are not limited to, the following:
wastewaters from ion exchange water treatment systems, water treatment
evaporator blowdown, laboratory and sampling streams, boiler blowdown,
floor drains, cooling tower basin cleaning wastes, recirculating house
service water systems, and wet scrubber air pollution control systems
whose primary purpose is particulate removal. Sanitary wastes, air
conditioning wastes, and wastewater from carbon capture or
sequestration systems are not included in this definition.
* * * * *
(e) The term fly ash means the ash that is carried out of the
furnace by a gas stream and collected by a capture device such as a
mechanical precipitator, electrostatic precipitator, or fabric filter.
Economizer ash is included in this definition when it is collected with
fly ash. Ash is not included in this definition when it is collected in
wet scrubber air pollution control systems whose primary purpose is
particulate removal.
* * * * *
(n) The term flue gas desulfurization (FGD) wastewater means any
process wastewater generated from a wet flue gas desulfurization
scrubber system, including any solids separation or solids dewatering
processes.
(o) The term flue gas mercury control wastewater means any process
wastewater generated from an air pollution control system installed or
operated for the purpose of removing mercury from flue gas. This
includes fly ash collection systems when the particulate control system
follows the injection of sorbents or implementation of other controls
to remove mercury from flue gas. Flue gas desulfurization systems are
not included in this definition.
(p) The term transport water means any process wastewater that is
used to convey fly ash or bottom ash from the ash collection equipment
and has direct contact with the ash.
(q) The term gasification wastewater means any process wastewater
generated from a system used to create synthesis gas from fuels such as
coal or petroleum coke. Gasification wastewater includes, but is not
limited to, the following: slag handling wastewater, sour/grey water
(which includes condensate generated for gas cooling, as well as other
wastestreams), CO2/steam stripper wastewater, air separation
unit blowdown, and sulfur recovery unit blowdown.
(r) The term combustion residual leachate means leachate from
landfills or surface impoundments containing residuals from the
combustion of fossil or fossil-derived fuel. Leachate includes liquid,
including any suspended or dissolved constituents in the liquid, that
has percolated through or drained from waste or other materials placed
in a landfill, or that pass through the containment structure (e.g.,
bottom, dikes, berms) of a surface impoundment. Leachate also includes
the terms seepage, leak, and leakage, which are generally used in
reference to leachate from an impoundment.
(s) The term oil-fired unit means a generating unit that uses oil
as the primary or secondary fuel source and does not use a gasification
process or any coal or petroleum coke as a fuel source. This definition
does not include units that use oil only for start up or flame-
stabilization purposes.
(t) The term sufficiently sensitive analytical method means a
method that ensures the sample-specific quantitation level for the
wastewater being analyzed is at or below the level of the effluent
limitation.
(u) The term nonchemical metal cleaning waste means any wastewater
resulting from the cleaning of any metal process equipment without
chemical cleaning compounds, including, but not limited to, boiler tube
cleaning, boiler fireside cleaning, and air preheater cleaning.
[[Page 34534]]
0
4. Section 423.12 is amended by:
0
a. Revising paragraphs (b)(11) and (12); and
0
b. Adding paragraph (b)(13).
The revised and added paragraphs read as follows:
Sec. 423.12 Effluent limitations guidelines representing the degree
of effluent reduction attainable by the application of the best
practicable control technology currently available (BPT).
* * * * *
(b) * * *
(11) The quantity of pollutants discharged in FGD wastewater, flue
gas mercury control wastewater, combustion residual leachate, or
gasification wastewater shall not exceed the quantity determined by
multiplying the flow of the applicable wastewater times the
concentration listed in the following table:
------------------------------------------------------------------------
BPT effluent limitations
-------------------------------------
Average of daily
Pollutant or pollutant property values for 30
Maximum for any 1 consecutive days
day (mg/l) shall not exceed
(mg/l)
------------------------------------------------------------------------
TSS............................... 100.0 30.0
Oil and grease.................... 20.0 15.0
------------------------------------------------------------------------
(12) At the permitting authority's discretion, the quantity of
pollutant allowed to be discharged may be expressed as a concentration
limitation instead of the any mass based limitations specified in
paragraphs (b)(3) through (b)(11) of this section. Concentration
limitations shall be those concentrations specified in this section.
(13) In the event that wastestreams from various sources are
combined for treatment or discharge, the quantity of each pollutant or
pollutant property controlled in paragraphs (b)(1) through (b)(12) of
this section attributable to each controlled waste source shall not
exceed the specified limitations for that waste source.
0
5. Section 423.13 is amended by:
0
a. Adding paragraph (f);
0
b. Revising paragraphs (g) and (h); and
0
c. Adding paragraphs (i) through (n).
Sec. 423.13 Effluent limitations guidelines representing the degree
of effluent reduction attainable by the application of the best
available technology economically achievable (BAT).
* * * * *
(f)(1) Except for those discharges to which paragraph (f)(2) of
this section applies, the quantity of pollutants discharged in
nonchemical metal cleaning wastes shall not exceed the quantity
determined by multiplying the flow of nonchemical metal cleaning wastes
times the concentration listed in the following table:
------------------------------------------------------------------------
BAT effluent limitations
-------------------------------------
Average of daily
Pollutant or pollutant property values for 30
Maximum for any 1 consecutive days
day (mg/l) shall not exceed
(mg/l)
------------------------------------------------------------------------
Copper, total..................... 1.0 1.0
Iron, total....................... 1.0 1.0
------------------------------------------------------------------------
(2) For those discharges of nonchemical metal cleaning waste that
are currently authorized pursuant to limitations based on requirements
in Sec. 423.12(b)(3) for low-volume waste, the quantity of pollutants
discharged in nonchemical metal cleaning wastes shall not exceed the
quantity determined by multiplying the flow of nonchemical metal
cleaning wastes times the concentration listed in Sec. 423.12(b)(3).
(g)(1) Except for those discharges to which paragraph (g)(2) of
this section applies, dischargers must meet the effluent limitations in
this paragraph by a date determined by the permitting authority that is
as soon as possible within the next permit cycle beginning July 1,
2017. These effluent limitations apply to pollutants in FGD wastewater
generated on or after the date the permitting authority has determined
is as soon as possible. Such effluent limitations shall not allow the
quantity of pollutants in FGD wastewater to exceed the quantity
determined by multiplying the flow of FGD wastewater times the
concentration listed in the following table:
------------------------------------------------------------------------
BAT effluent limitations
---------------------------------------
Average of daily
Pollutant or pollutant property Maximum for any 1 values for 30
day consecutive days
shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)........... 8 6
Mercury, total (ng/L)........... 242 119
Selenium, total (ug/L).......... 16 10
Nitrate/nitrate as N (mg/L)..... 0.17 0.13
------------------------------------------------------------------------
[[Page 34535]]
(2) For any electric generating unit with a total nameplate
capacity of less than or equal to 50 megawatts or that is an oil-fired
unit, the quantity of pollutants discharged in FGD wastewater shall not
exceed the quantity determined by multiplying the flow of FGD
wastewater times the concentration listed in Sec. 423.12(b)(11).
(3) A discharger must demonstrate compliance with the effluent
limitations in paragraph (g)(1) of this section, as applicable, by
monitoring for all pollutants (except pH) at a point prior to use of
the FGD wastewater in any other plant process or commingling of the FGD
wastewater with any water or other process wastewater, except for any
combustion residual leachate or any other FGD wastewater. Compliance
with the effluent limitations must reflect results obtained from
sufficiently sensitive analytical methods.
Note to (g): All proposed revisions to Sec. 423.13(g) reflect
proposed Option 4a, Option 3, and Option 3b (for units located at
facilities with a total wet-scrubbed capacity of 2,000 MW or more),
only. Under proposed Option 3a and Option 3b (for units located at
facilities with a total wet-scrubbed capacity of less than 2,000
MW), BAT would continue to need to be determined on a site-specific
basis using best professional judgment.
(h)(1) Except for those discharges to which paragraph (h)(2) of
this section applies, dischargers must meet the discharge prohibition
in this paragraph by a date determined by the permitting authority that
is as soon as possible within the next permit cycle beginning July 1,
2017. There shall be no discharge of wastewater pollutants from fly ash
transport water generated on or after the date the permitting authority
determines is as soon as possible. Whenever fly ash transport water is
used in any other plant process or is sent to a treatment system at the
plant, the resulting effluent must comply with the discharge
prohibition in this paragraph.
(2) For any electric generating unit with a total nameplate
generating capacity of less than or equal to 50 megawatts or that is an
oil-fired unit, the quantity of pollutants discharged in fly ash
transport water shall not exceed the quantity determined by multiplying
the flow of fly ash transport water times the concentration listed in
Sec. 423.12(b)(4).
(i)(1) Except for those discharges to which paragraph (i)(2) of
this section applies, dischargers must meet the discharge prohibition
in this paragraph by a date determined by the permitting authority that
is as soon as possible within the next permit cycle beginning July 1,
2017. There shall be no discharge of wastewater pollutants from flue
gas mercury control wastewater generated on or after the date the
permitting authority determines is as soon as possible. Whenever flue
gas mercury control wastewater is used in any other plant process or is
sent to a treatment system at the plant, the resulting effluent must
comply with the discharge prohibition in this paragraph.
(2) For any electric generating unit with a total nameplate
generating capacity of less than or equal to 50 megawatts or that is an
oil-fired unit, the quantity of pollutants discharged in flue gas
mercury control wastewater shall not exceed the quantity determined by
multiplying the flow of flue gas mercury control wastewater times the
concentration listed in Sec. 423.12(b)(11).
(j)(1) Except for those discharges to which paragraph (j)(2) of
this section applies, dischargers must meet the effluent limitations in
this paragraph by a date determined by the permitting authority that is
as soon as possible within the next permit cycle beginning July 1,
2017. Such effluent limitations shall not allow the quantity of
pollutants in gasification wastewater to exceed the quantity determined
by multiplying the flow of gasification wastewater times the
concentration listed in the following table:
------------------------------------------------------------------------
BAT effluent limitations
---------------------------------------
Average of daily
Pollutant or pollutant property Maximum for any 1 values for 30
day consecutive days
shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)........... 4 (\1\)
Mercury, total (ng/L)........... 1.76 1.29
Selenium, total (ug/L).......... 453 227
Total dissolved solids (mg/L)... 38 22
------------------------------------------------------------------------
\1\ This regulation does not specify this type of limitation for this
pollutant; however, permitting authorities may do so as appropriate.
(2) For any electric generating unit with a total nameplate
generating capacity of less than or equal to 50 megawatts or that is an
oil-fired unit, the quantity of pollutants discharged in gasification
wastewater shall not exceed the quantity determined by multiplying the
flow of gasification wastewater times the concentration listed in Sec.
423.12(b)(11).
(3) A discharger must demonstrate compliance with the effluent
limitations in paragraph (j)(1) of this section, as applicable, by
monitoring for all pollutants (except pH) at a point prior to use of
the gasification wastewater in any other plant process or commingling
of the gasification wastewater with water or any other process
wastewater. Compliance with the effluent limitations must reflect
results obtained from sufficiently sensitive analytical methods.
(k)(1) Except for those discharges to which paragraph (k)(2) of
this section applies, dischargers must meet the discharge
prohibition in this paragraph by a date determined by the permitting
authority that is as soon as possible within the next permit cycle
beginning July 1, 2017. There shall be no discharge of wastewater
pollutants from bottom ash transport water generated on or after the
date the permitting authority determines is as soon as possible.
Whenever bottom ash transport water is used in any other plant
process or is sent to a treatment system at the plant, the resulting
effluent must comply with the discharge prohibition in this
paragraph.
(2) For any electric generating unit with a total nameplate
generating capacity of less than or equal to 400 megawatts or that is
an oil-fired unit, the quantity of pollutants discharged in bottom ash
transport water shall not exceed the quantity determined by multiplying
the flow of the applicable wastewater times the concentration in Sec.
423.12(b)(4).
Note to (k): All proposed revisions to Sec. 423.13(k) reflect
proposed Option 4a, only. Under proposed Option 3, Option 3a, and
Option 3b, Sec. 423.13(k) would be revised to specify that the
quantity of pollutants discharged in bottom ash transport water
shall not exceed the quantity determined by multiplying the flow of
the applicable wastewater times the concentration in Sec.
423.12(b)(4).
[[Page 34536]]
(l) The quantity of pollutants discharged in combustion residual
leachate shall not exceed the quantity determined by multiplying the
flow of leachate times the concentration listed in Sec. 423.12(b)(11).
(m) At the permitting authority's discretion, the quantity of
pollutant allowed to be discharged may be expressed as a concentration
limitation instead of any mass based limitations specified in
paragraphs (b) through (l) of this section. Concentration limitations
shall be those concentrations specified in this section.
(n) In the event that wastestreams from various sources are
combined for treatment or discharge, the quantity of each pollutant or
pollutant property controlled in paragraphs (a) through (m) of this
section attributable to each controlled waste source shall not exceed
the specified limitation for that waste source.
0
6. Section 423.15 is amended by revising paragraphs (a) and (b) to read
as follows:
Sec. 423.15 New source performance standards (NSPS).
(a) 1982 New source performance standards. Any new source as of
November 19, 1982, subject to this subpart, must achieve the following
new source performance standards and the revised requirements of Sec.
423.13 of this part, published on [insert date of publication of final
rule]:
(1) The pH of all discharges, except once through cooling water,
shall be within the range of 6.0-9.0.
(2) There shall be no discharge of polychlorinated biphenyl
compounds such as those commonly used for transformer fluid.
(3) The quantity of pollutants discharged from low volume waste
sources shall not exceed the quantity determined by multiplying the
flow of low volume waste sources times the concentration listed in the
following table:
------------------------------------------------------------------------
Pollutant or pollutant property
-------------------------------------
Average of daily
NSPS values for 30
Maximum for any consecutive days
1 day (mg/l) shall not exceed
(mg/l)
------------------------------------------------------------------------
TSS............................... 100.0 30.0
Oil and grease.................... 20.0 15.0
------------------------------------------------------------------------
(4) The quantity of pollutants discharged in chemical metal
cleaning wastes shall not exceed the quantity determined by multiplying
the flow of chemical metal cleaning wastes times the concentration
listed in the following table:
------------------------------------------------------------------------
NSPS
-------------------------------------
Average of daily
Pollutant or pollutant property values for 30
Maximum for any 1 consecutive days
day (mg/l) shall not exceed
(mg/l)
------------------------------------------------------------------------
TSS............................... 100.0 30.0
Oil and grease.................... 20.0 15.0
Copper, total..................... 1.0 1.0
Iron, total....................... 1.0 1.0
------------------------------------------------------------------------
(5) [Reserved].
(6) The quantity of pollutants discharged in bottom ash transport
water shall not exceed the quantity determined by multiplying the flow
of the bottom ash transport water times the concentration listed in the
following table:
------------------------------------------------------------------------
NSPS
-------------------------------------
Average of daily
Pollutant or pollutant property values for 30
Maximum for any1 consecutive days
day (mg/l) shall not exceed
(mg/l)
------------------------------------------------------------------------
TSS............................... 100.0 30.0
Oil and grease.................... 20.0 15.0
------------------------------------------------------------------------
(7) There shall be no discharge of wastewater pollutants from fly
ash transport water. Whenever fly ash transport water is used in any
other plant process or is sent to a treatment system at the plant, the
resulting effluent must comply with the discharge prohibition in this
paragraph.
(8)(i) For any plant with a total rated electric generating
capacity of 25 or more megawatts, the quantity of pollutants discharged
in once through cooling water from each discharge point shall not
exceed the quantity determined by multiplying the flow of once through
cooling water from each discharge point times the concentration listed
in the following table:
[[Page 34537]]
------------------------------------------------------------------------
NSPS
----------------
Pollutant or pollutant property Maximum
concentrations
(mg/l)
------------------------------------------------------------------------
Total residual chlorine................................ 0.20
------------------------------------------------------------------------
(ii) Total residual chlorine may not be discharged from any single
generating unit for more than two hours per day unless the discharger
demonstrates to the permitting authority that discharge for more than
two hours is required for macroinvertebrate control. Simultaneous
multi-unit chlorination is permitted.
(9)(i) For any plant with a total rated generating capacity of less
than 25 megawatts, the quantity of pollutants discharged in once
through cooling water shall not exceed the quantity determined by
multiplying the flow of once through cooling water sources times the
concentration listed in the following table:
------------------------------------------------------------------------
Maximum Average
Pollutant or pollutant property concentration concentration
(mg/l) (mg/l)
------------------------------------------------------------------------
Free available chlorine........... 0.5 0.2
------------------------------------------------------------------------
(ii) Neither free available chlorine nor total residual chlorine
may be discharged from any unit for more than two hours in any one day
and not more than one unit in any plant may discharge free available or
total residual chlorine at any one time unless the utility can
demonstrate to the Regional Administrator or State, if the State has
NPDES permit issuing authority, that the units in a particular location
cannot operate at or below this level of chlorination.
(10)(i) The quantity of pollutants discharged in cooling tower
blowdown shall not exceed the quantity determined by multiplying the
flow of cooling tower blowdown times the concentration listed below:
------------------------------------------------------------------------
Maximum Average
Pollutant or pollutant property concentration concentration
(mg/l) (mg/l)
------------------------------------------------------------------------
Free available chlorine........... 0.5 0.2
------------------------------------------------------------------------
------------------------------------------------------------------------
NSPS
-------------------------------------
Average of daily
Pollutant or pollutant property Maximum for any values for 30
1 day consecutive days
concentration shall not exceed
(mg/l) (mg/l)
------------------------------------------------------------------------
The 126 priority pollutants (\1\) (\1\)
(Appendix A) contained in
chemicals added for cooling tower
maintenance, except:.............
Chromium, total................... 0.2 0.2
Zinc, total....................... 1.0 1.0
------------------------------------------------------------------------
\1\ No detectable amount.
(ii) Neither free available chlorine nor total residual chlorine
may be discharged from any unit for more than two hours in any one day
and not more than one unit in any plant may discharge free available or
total residual chlorine at any one time unless the utility can
demonstrate to the Regional Administrator or State, if the State has
NPDES permit issuing authority, that the units in a particular location
cannot operate at or below this level of chlorination.
(iii) At the permitting authority's discretion, instead of the
monitoring in 40 CFR 122.11(b), compliance with the limitations for the
126 priority pollutants in paragraph (a)(10)(i) of this section may be
determined by engineering calculations which demonstrate that the
regulated pollutants are not detectable in the final discharge by the
analytical methods in 40 CFR part 136.
(11) Subject to the provisions of Sec. 423.15(a)(12), the quantity
or quality of pollutants or pollutant parameters discharged in coal
pile runoff shall not exceed the limitations specified below:
------------------------------------------------------------------------
NSPS
Pollutant or pollutant property -------------------------------------
For any time
------------------------------------------------------------------------
TSS............................... not to exceed 50 mg/l.
------------------------------------------------------------------------
(12) Any untreated overflow from facilities designed, constructed,
and operated to treat the coal pile runoff which results from a 10
year, 24 hour rainfall event shall not be subject to the limitations in
Sec. 423.15(a)(11).
(13) At the permitting authority's discretion, the quantity of
pollutant allowed to be discharged may be expressed as a concentration
limitation instead of any mass based limitations specified in
paragraphs (a)(3) through (a)(10) of this section. Concentration limits
shall be based on the concentrations specified in this section.
(14) In the event that wastestreams from various sources are
combined for treatment or discharge, the quantity of each pollutant or
pollutant property controlled in paragraphs (a)(1) through (a)(13) of
this section attributable to each controlled waste source shall not
exceed the specified limitation for that waste source.
(The information collection requirements contained in paragraphs
(a)(8)(ii), (a)(9)(ii), and (a)(10)(ii) were approved by the Office
of Management and Budget under control number 2040-0040. The
information collection requirements contained in paragraph
(a)(10)(iii) were approved under control number 2040-0033.)
(b) 2014 New source performance standards. Any new source as of
[insert date of publication of final rule], subject
[[Page 34538]]
to this subpart, must achieve the following new source performance
standards:
(1) The pH of all discharges, except once through cooling water,
shall be within the range of 6.0-9.0.
(2) There shall be no discharge of polychlorinated biphenyl
compounds such as those commonly used for transformer fluid.
(3) The quantity of pollutants discharged from low volume waste
sources shall not exceed the quantity determined by multiplying the
flow of low volume waste sources times the concentration listed in the
following table:
------------------------------------------------------------------------
NSPS
-------------------------------------
Average of daily
Pollutant or pollutant property values for 30
Maximum for any consecutive days
1 day (mg/l) shall not exceed
(mg/l)
------------------------------------------------------------------------
TSS............................... 100.0 30.0
Oil and grease.................... 20.0 15.0
------------------------------------------------------------------------
(4) The quantity of pollutants discharged in chemical metal
cleaning wastes shall not exceed the quantity determined by multiplying
the flow of chemical metal cleaning wastes times the concentration
listed in the following table:
------------------------------------------------------------------------
NSPS
-------------------------------------
Average of daily
Pollutant or pollutant property values for 30
Maximum for any consecutive days
1 day (mg/l) shall not exceed
(mg/l)
------------------------------------------------------------------------
TSS............................... 100.0 30.0
Oil and grease.................... 20.0 15.0
Copper, total..................... 1.0 1.0
Iron, total....................... 1.0 1.0
------------------------------------------------------------------------
(5) The quantity of pollutants discharged in nonchemical metal
cleaning wastes shall not exceed the quantity determined by multiplying
the flow of nonchemical metal cleaning wastes times the concentration
listed in the following table:
------------------------------------------------------------------------
NSPS
-------------------------------------
Average of daily
Pollutant or pollutant property values for 30
Maximum for any consecutive days
1 day (mg/l) shall not exceed
(mg/l)
------------------------------------------------------------------------
TSS............................... 100.0 30.0
Oil and grease.................... 20.0 15.0
Copper, total..................... 1.0 1.0
Iron, total....................... 1.0 1.0
------------------------------------------------------------------------
(6) There shall be no discharge of wastewater pollutants from
bottom ash transport water. Whenever bottom ash transport water is used
in any other plant process or is sent to a treatment system at the
plant, the resulting effluent must comply with the discharge
prohibition in this paragraph.
(7) There shall be no discharge of wastewater pollutants from fly
ash transport water. Whenever fly ash transport water is used in any
other plant process or is sent to a treatment system at the plant, the
resulting effluent must comply with the discharge prohibition in this
paragraph.
(8)(i) For any plant with a total rated electric generating
capacity of 25 or more megawatts, the quantity of pollutants discharged
in once through cooling water from each discharge point shall not
exceed the quantity determined by multiplying the flow of once through
cooling water from each discharge point times the concentration listed
in the following table:
------------------------------------------------------------------------
NSPS
----------------
Pollutant or pollutant property Maximum
concentration
(mg/l)
------------------------------------------------------------------------
Total residual chlorine................................ 0.20
------------------------------------------------------------------------
(ii) Total residual chlorine may not be discharged from any single
generating
[[Page 34539]]
unit for more than two hours per day unless the discharger demonstrates
to the permitting authority that discharge for more than two hours is
required for macroinvertebrate control. Simultaneous multi-unit
chlorination is permitted.
(9)(i) For any plant with a total rated generating capacity of less
than 25 megawatts, the quantity of pollutants discharged in once
through cooling water shall not exceed the quantity determined by
multiplying the flow of once through cooling water sources times the
concentration listed in the following table:
------------------------------------------------------------------------
NSPS
-------------------------------------
Pollutant or pollutant property Maximum Average
concentration concentration
(mg/l) (mg/l)
------------------------------------------------------------------------
Free available chlorine........... 0.5 0.2
------------------------------------------------------------------------
(ii) Neither free available chlorine nor total residual chlorine
may be discharged from any unit for more than two hours in any one day
and not more than one unit in any plant may discharge free available or
total residual chlorine at any one time unless the utility can
demonstrate to the Regional Administrator or State, if the State has
NPDES permit issuing authority, that the units in a particular location
cannot operate at or below this level of chlorination.
(10)(i) The quantity of pollutants discharged in cooling tower
blowdown shall not exceed the quantity determined by multiplying the
flow of cooling tower blowdown times the concentration listed below:
------------------------------------------------------------------------
NSPS
-------------------------------------
Pollutant or pollutant property Maximum Average
concentration concentration
(mg/l) (mg/l)
------------------------------------------------------------------------
Free available chlorine........... 0.5 0.2
------------------------------------------------------------------------
------------------------------------------------------------------------
Average of daily
values for 30
Pollutant or pollutant property Maximum for any consecutive days
1 day (mg/l) shall not exceed
(mg/l)
------------------------------------------------------------------------
The 126 priority pollutants (\1\) (\1\)
(Appendix A) contained in
chemicals added for cooling tower
maintenance, except:.............
Chromium, total................... 0.2 0.2
Zinc, total....................... 1.0 1.0
------------------------------------------------------------------------
\1\ No detectable amount.
(ii) Neither free available chlorine nor total residual chlorine
may be discharged from any unit for more than two hours in any one day
and not more than one unit in any plant may discharge free available or
total residual chlorine at any one time unless the utility can
demonstrate to the Regional Administrator or State, if the State has
NPDES permit issuing authority, that the units in a particular location
cannot operate at or below this level of chlorination.
(iii) At the permitting authority's discretion, instead of the
monitoring in 40 CFR 122.11(b), compliance with the limitations for the
126 priority pollutants in paragraph (b)(10)(i) of this section may be
determined by engineering calculations which demonstrate that the
regulated pollutants are not detectable in the final discharge by the
analytical methods in 40 CFR part 136.
(11) Subject to the provisions of Sec. 423.15(b)(12), the quantity
or quality of pollutants or pollutant parameters discharged in coal
pile runoff shall not exceed the limitations specified below:
------------------------------------------------------------------------
NSPS
Pollutant or pollutant property -------------------------------------
For any time
------------------------------------------------------------------------
TSS............................... not to exceed 50 mg/l.
------------------------------------------------------------------------
(12) Any untreated overflow from facilities designed, constructed,
and operated to treat the coal pile runoff which results from a 10
year, 24 hour rainfall event shall not be subject to the limitations in
Sec. 423.15(b)(11).
(13)(i) The quantity of pollutants discharged in FGD wastewater
shall not exceed the quantity determined by multiplying the flow of FGD
wastewater times the concentration listed in the following table:
------------------------------------------------------------------------
NSPS
---------------------------------------
Average of daily
Pollutant or pollutant property Maximum for any1 values for 30
day (mg/l) consecutive days
shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)........... 8 6
[[Page 34540]]
Mercury, total (ng/L)........... 242 119
Selenium, tota (ug/L)........... 16 10
Nitrate/nitrite as N (mg/L)..... 0.17 0.13
------------------------------------------------------------------------
(ii) A discharger must demonstrate compliance with the standards in
paragraph (b)(13)(i) of this section, as applicable, by monitoring for
all pollutants (except pH) at a point prior to use of the FGD
wastewater in any other plant process or commingling of the FGD
wastewater with any water or other process wastewater, except for any
combustion residual leachate or any other FGD wastewater. Compliance
with the standards must reflect results obtained from sufficiently
sensitive analytical methods.
(14) There shall be no discharge of wastewater pollutants from flue
gas mercury control wastewater. Whenever flue gas mercury control
wastewater is used in any other plant process or is sent to a treatment
system at the plant, the resulting effluent must comply with the
discharge prohibition in this paragraph.
(15)(i) The quantity of pollutants discharged in gasification
wastewater shall not exceed the quantity determined by multiplying the
flow of gasification wastewater times the concentration listed in the
following table:
------------------------------------------------------------------------
NSPS
---------------------------------------
Average ff daily
Pollutant or pollutant property Maximum for any 1 values for 30
day consecutive days
shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)........... 4 (\1\)
Mercury, total (ng/L)........... 1.76 1.29
Selenium, total (ug/L).......... 453 227
Total dissolved solids (mg/L)... 38 22
------------------------------------------------------------------------
\1\ This regulation does not specify this type of limitation for this
pollutant; however, permitting authorities may do so as appropriate.
(ii) A discharger must demonstrate compliance with the standards in
paragraph (b)(15)(i) of this section, as applicable, by monitoring for
all pollutants (except pH) prior to use of the gasification wastewater
in any other plant process or commingling of the gasification
wastewater with any water or other process wastewater. Compliance with
the standards must reflect results obtained from sufficiently sensitive
analytical methods.
(16)(i) The quantity of pollutants discharged in combustion
residual leachate shall not exceed the quantity determined by
multiplying the flow of combustion residual leachate times the
concentration listed in the following table:
------------------------------------------------------------------------
NSPS
-------------------------------------
Average of daily
Pollutant or pollutant property Maximum for any 1 values for 30
day consecutive days
shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)............. 8 6
Mercury, total (ng/L)............. 242 119
------------------------------------------------------------------------
(ii) A discharger must demonstrate compliance with the standards in
paragraph (b)(16)(i) of this section, as applicable, by monitoring for
all pollutants (except pH) at a point prior to use of the combustion
residual leachate in any other plant process or commingling of the
combustion residual leachate with any water or other process
wastewater, except for any FGD wastewater or any other combustion
residual leachate. Compliance with the effluent limitations must
reflect results obtained from sufficiently sensitive analytical
methods.
(17) At the permitting authority's discretion, the quantity of
pollutant allowed to be discharged may be expressed as a concentration
limitation instead of any mass based limitations specified in
paragraphs (b)(3) through (b)(16) of this section. Concentration limits
shall be based on the concentrations specified in this section.
(18) In the event that wastestreams from various sources are
combined for treatment or discharge, the quantity of each pollutant or
pollutant property controlled in paragraphs (b)(1) through (b)(16) of
this section attributable to each controlled waste source shall not
exceed the specified limitation for that waste source.
0
7. Section 423.16 is amended by adding paragraphs (c) and (e) through
(i) to read as follows:
Sec. 423.16 Pretreatment standards for existing sources (PSES).
* * * * *
(c) Except for those discharges of nonchemical metal cleaning waste
that are currently authorized without meeting standards for copper, the
pollutants discharged in nonchemical metal cleaning wastes shall not
exceed
[[Page 34541]]
the concentration listed in the following table:
------------------------------------------------------------------------
PSES
pretreatment
standards
Pollutant or pollutant property ----------------
Maximum for 1
day (mg/l)
------------------------------------------------------------------------
Copper, total.......................................... 1.0
------------------------------------------------------------------------
* * * * *
(e)(1) For any electric generating unit with a total nameplate
generating capacity of more than 50 megawatts and that is not an oil-
fired unit, dischargers must meet the standards in this paragraph by a
date determined by the control authority that is as soon as possible
beginning July 1, 2017. These standards apply to pollutants in FGD
wastewater generated on or after a date determined by the control
authority that is as soon as possible beginning July 1, 2017. Such
effluent limitations shall not allow the quantity of pollutants in FGD
wastewater to exceed the quantity determined by multiplying the flow of
FGD wastewater times the concentration listed in the following table:
------------------------------------------------------------------------
PSES
---------------------------------------
Average of daily
Pollutant or pollutant property Maximum for any 1 values for 30
day consecutive days
shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)........... 8 6
Mercury, total (ng/L)........... 242 119
Selenium, total (ug/L).......... 16 10
Nitrate/nitrite as N (mg/L)..... 0.17 0.13
------------------------------------------------------------------------
(2) A discharger must demonstrate compliance with the standards in
paragraph (e)(1) of this section, as applicable, by monitoring for all
pollutants (except pH) at a point prior to use of the FGD wastewater in
any other plant process or commingling of the FGD wastewater with any
water or other process wastewater, except for any combustion residual
leachate or FGD wastewater. Compliance with the effluent limitations
must reflect results obtained from sufficiently sensitive analytical
methods.
Note to (e): All proposed revisions to section 423.16(e) reflect
proposed Option 4a, Option 3, and Option 3b (for units located a
facilities with a total wet-scrubbed capacity of 2,000 MW or more),
only. Under proposed Option 3a and Option 3b (for units located at
facilities with a total wet-scrubbed capacity of less than 2,000
MW), POTWS would need to develop local limits to address the
introduction of pollutants found in FGD wastewater by steam electric
plants to the POTWs that cause pass through or interference, as
specified in 40 CFR 403.5(c)(2).
(f) For any electric generating unit with a total nameplate
generating capacity of more than 50 megawatts and that is not an oil-
fired unit, there shall be no discharge of wastewater pollutants from
fly ash transport water generated on or after a date determined by the
control authority that is as soon as possible beginning July 1, 2017.
Whenever fly ash transport water is used in any other plant process or
is sent to a treatment system at the plant, the resulting effluent must
comply with the discharge prohibition in this paragraph.
(g) For any electric generating unit with a total nameplate
generating capacity of more than 400 megawatts and that is not an oil-
fired unit, there shall be no discharge of wastewater pollutants from
bottom ash transport water generated on or after a date determined by
the control authority that is as soon as possible beginning July 1,
2017. Whenever bottom ash transport water is used in any other plant
process or is sent to a treatment system at the plant, the resulting
effluent must comply with the discharge prohibition in this paragraph.
Note to (g): All proposed revisions to section 423.16(g) reflect
proposed Option 4a, only. For proposed Option 3, Option 3a, and
Option 3b, the regulations would not specify a PSES for bottom ash
transport water.
(h) For any electric generating unit with a total nameplate
generating capacity of more than 50 megawatts and that is not an oil-
fired unit, there shall be no discharge of wastewater pollutants from
flue gas mercury control wastewater generated on or after a date
determined by the control authority that is as soon as possible
beginning July 1, 2017. Whenever flue gas mercury control wastewater is
used in any other plant process or is sent to a treatment system at the
plant, the resulting effluent must comply with the discharge
prohibition in this paragraph.
(i)(1) For any electric generating unit with a total nameplate
generating capacity of more than 50 megawatts and that is not an oil-
fired unit, dischargers must meet the standards in this paragraph by a
date determined by the control authority that is as soon as possible
beginning July 1, 2017. These standards apply to pollutants in
gasification wastewater generated on or after a date determined by the
control authority that is as soon as possible beginning July 1, 2017.
Such effluent limitations shall not allow the quantity of pollutants in
gasification wastewater to exceed the quantity determined by
multiplying the flow of gasification wastewater times the concentration
listed in the following table:
------------------------------------------------------------------------
PSES
---------------------------------------
Average of daily
Pollutant or pollutant property Maximum for any 1 values for 30
day consecutive days
shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)........... 4 (\1\)
Mercury, total (ng/L)........... 1.76 1.29
Selenium, total (ug/L).......... 453 227
Total dissolved solids (mg/L)... 38 22
------------------------------------------------------------------------
\1\ This regulation does not specify this type of limitation for this
pollutant; however, permitting authorities may do so as appropriate.
[[Page 34542]]
(2) A discharger must demonstrate compliance with the standards in
paragraph (i)(1) of this section, as applicable, by monitoring for all
pollutants (except pH) at a point prior to use of the gasification
wastewater in any other plant process or commingling of the
gasification wastewater with any water or other process wastewater.
Compliance with the standards must reflect results obtained from
sufficiently sensitive analytical methods.
0
8. Section 423.17 is amended by revising paragraphs (a) and (b) to read
as follows:
Sec. 423.17 Pretreatment standards for new sources (PSNS).
(a) 1982 Pretreatment standards for new sources. Except as provided
in 40 CFR 403.7, any new source as of November 19, 1982, subject to
this subpart, which introduces pollutants into a publicly owned
treatment works must comply with 40 CFR part 403 and the following
pretreatment standards for new sources (PSNS), and the revised
requirements of Sec. 423.16 of this part, published on [insert date of
publication of final rule]:
(1) There shall be no discharge of polychlorinated biphenyl
compounds such as those used for transformer fluid.
(2) The pollutants discharged in chemical metal cleaning wastes
shall not exceed the concentration listed in the following table:
------------------------------------------------------------------------
PSNS
----------------
Pollutant or pollutant property Maximum for any
1 day
------------------------------------------------------------------------
Copper, total.......................................... 1.0
------------------------------------------------------------------------
(3) [Reserved].
(4)(i) The pollutants discharged in cooling tower blowdown shall
not exceed the concentration listed in the following table:
------------------------------------------------------------------------
PSNS
----------------
Pollutant or pollutant property Maximum for any
time (mg/l)
------------------------------------------------------------------------
The 126 priority pollutants (Appendix A) contained in (\1\)
chemicals added for cooling tower maintenance, except:
Chromium, total........................................ 0.2
Zinc, total............................................ 1.0
------------------------------------------------------------------------
\1\ No detectable amount.
(ii) At the permitting authority's discretion, instead of the
monitoring in 40 CFR 122.11(b), compliance with the limitations for the
126 priority pollutants in paragraph (a)(4)(i) of this section may be
determined by engineering calculations which demonstrate that the
regulated pollutants are not detectable in the final discharge by the
analytical methods in 40 CFR part 136.
(5) There shall be no discharge of wastewater pollutants from fly
ash transport water. Whenever fly ash transport water is used in any
other plant process or is sent to a treatment system at the plant, the
resulting effluent must comply with the discharge prohibition in this
paragraph.
(b) 2014 Pretreatment standards for new sources. Except as provided
in 40 CFR 403.7, any new source as of [insert date of publication of
final rule], subject to this subpart, which introduces pollutants into
a publicly owned treatment works must comply with 40 CFR part 403 and
the following pretreatment standards for new sources (PSNS):
(1) There shall be no discharge of polychlorinated biphenyl
compounds such as those used for transformer fluid.
(2) The pollutants discharged in chemical metal cleaning wastes
shall not exceed the concentration listed in the following table:
------------------------------------------------------------------------
PSNS
----------------
Pollutant or pollutant property Maximum for 1
day (mg/l)
------------------------------------------------------------------------
Copper, total.......................................... 1.0
------------------------------------------------------------------------
(3) The pollutants discharged in nonchemical metal cleaning wastes
shall not exceed the concentration listed in the following table:
------------------------------------------------------------------------
PSNS
----------------
Pollutant or pollutant property Maximum for 1
day (mg/l)
------------------------------------------------------------------------
Copper, total.......................................... 1.0
------------------------------------------------------------------------
(4)(i) The pollutants discharged in cooling tower blowdown shall
not exceed the concentration listed in the following table:
------------------------------------------------------------------------
PSNS
----------------
Pollutant or pollutant property Maximum for any
time (mg/l)
------------------------------------------------------------------------
The 126 priority pollutants (Appendix A) contained in (\1\)
chemicals added for cooling tower maintenance, except:
Chromium, total........................................ 0.2
Zinc, total............................................ 1.0
------------------------------------------------------------------------
\1\ No detectable amount.
(ii) At the permitting authority's discretion, instead of the
monitoring in 40 CFR 122.11(b), compliance with the limitations for the
126 priority pollutants in paragraph (b)(4)(i) of this section may be
determined by engineering calculations which demonstrate that the
regulated pollutants are not detectable in the final discharge by the
analytical methods in 40 CFR part 136.
(5) There shall be no discharge of wastewater pollutants from fly
ash transport water. Whenever fly ash transport water is used in any
other plant process or is sent to a treatment system at the plant, the
resulting effluent must comply with the discharge prohibition in this
paragraph.
(6)(i) The quantity of pollutants discharged in FGD wastewater
shall not exceed the quantity determined by multiplying the flow of FGD
wastewater times the concentration listed in the following table:
----------------------------------------------------------------------------------------------------------------
PSNS
---------------------------------
Average
daily
Pollutant or values for
pollutant property Maximum for any 1 30
day consecutive
days shall
not exceed
----------------------------------------------------------------------------------------------------- -------------
Arsenic, total (ug/L)........................................ 8 6
Mercury, total (ng/L)........................................ 242 119
Selenium, total (ug/L)....................................... 16 10
Nitrate/nitrite as N (mg/L).................................. 0.17 0.13
----------------------------------------------------------------------------------------------------------------
[[Page 34543]]
(ii) A discharger must demonstrate compliance with the standards in
paragraph (b)(6)(i) of this section, as applicable, by monitoring for
all pollutants (except pH) at a point prior to use of the FGD
wastewater in any other plant process or commingling of the FGD
wastewater with any water or other process wastewater, except for any
combustion residual leachate or any other FGD wastewater. Compliance
with the standards must reflect results obtained from sufficiently
sensitive analytical methods.
(7) There shall be no discharge of wastewater pollutants from flue
gas mercury control wastewater. Whenever flue gas mercury control
wastewater is used in any other plant process or is sent to a treatment
system at the plant, the resulting effluent must comply with the
discharge prohibition in this paragraph.
(8) There shall be no discharge of wastewater pollutants from
bottom ash transport water. Whenever bottom ash transport water is used
in any other plant process or is sent to a treatment system at the
plant, the resulting effluent must comply with the discharge
prohibition in this paragraph.
(9)(i) The quantity of pollutants discharged in gasification
wastewater shall not exceed the quantity determined by multiplying the
flow of gasification wastewater times the concentration listed in the
following table:
----------------------------------------------------------------------------------------------------------------
PSNS
---------------------------------
Average
daily
Pollutant or values for
pollutant property Maximum for any 1 30
day consecutive
days shall
not exceed
----------------------------------------------------------------------------------------------------- -------------
Arsenic, total (ug/L)........................................ 4 (\1\)
Mercury, total (ng/L)........................................ 1.76 1.29
Selenium, total (ug/L)....................................... 453 227
Total dissolved solids (mg/L)................................ 38 22
----------------------------------------------------------------------------------------------------------------
\1\ This regulation does not specify this type of limitation for this pollutant; however, permitting authorities
may do so as appropriate.
(ii) A discharger must demonstrate compliance with the standards in
paragraph (b)(9)(i) of this section, as applicable, by monitoring for
all pollutants (except pH) at a point prior to use of the gasification
wastewater in any other plant process or commingling of the
gasification wastewater with any water or other process wastewater.
Compliance with the standards must reflect results obtained from
sufficiently sensitive analytical methods.
(10)(i) The quantity of pollutants discharged in combustion
residual leachate shall not exceed the quantity determined by
multiplying the flow of combustion residual leachate times the
concentration listed in the following table:
----------------------------------------------------------------------------------------------------------------
PSNS
--------------------------------
Average
Pollutant or daily
pollutant values for
property Maximum for any 30
1 day consecutive
days shall
not exceed
----------------------------------------------------------------------------------------------------- -------------
Arsenic, total (ug/L).......................................... 8 6
Mercury, total (ng/L).......................................... 242 119
----------------------------------------------------------------------------------------------------------------
(ii) A discharger must demonstrate compliance with the standards in
paragraph (b)(10)(i) of this section, as applicable, by monitoring for
all pollutants (except pH) at a point prior to use of the combustion
residual leachate in any other plant process or commingling of the
combustion residual leachate with any water or other process
wastewater, except for any FGD wastewater or any other combustion
residual leachate. Compliance with the effluent limitations must
reflect results obtained from sufficiently sensitive analytical
methods.
* * * * *
[FR Doc. 2013-10191 Filed 6-6-13; 8:45 am]
BILLING CODE 6560-50-P